**UNITEDSTATESSECURITIES AND EXCHANGE COMMISSION**

**WASHINGTON,D.C. 20549**

 

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**FORM 10-Q**

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| **(Mark One)** |
|----------------|
|           |
| **x**          | **Quarterly report pursuant to  Section 13 or 15(d) of the Securities Exchange Act of 1934** |
|           |   |
| ** **     | **For the quarterly period ended March 31,  2008 or** |
|           |   |
| **o**          | **Transition report pursuant to  Section 13 or 15(d) of the Securities Exchange Act of 1934** |
|           |   |
|           | **For the transition period from                                to                         .** |

 

**Commission file number: 1-3368**

 

**THE EMPIRE DISTRICT ELECTRIC COMPANY**

(Exact name of registrant as specified in its charter)

 

| **Kansas**                                | ** ** | **44-0236370**                        |
|-------------------------------------------|------------|---------------------------------------|
| (State of  Incorporation)                 |       | (I.R.S. Employer  Identification No.) |
|                                      |       |                                  |
| **602  Joplin Avenue, Joplin, Missouri**  |       | **64801**                             |
| (Address of  principal executive offices) |       | (zip code)                            |

 

Registrant’s telephone number: **(417) 625-5100**

 

Indicate by checkmark whether the registrant (1) has filed all reports required to be filedby Section 13 or 15(d) of the Securities Exchange Act of 1934 duringthe preceding 12 months (or for such shorter period that the registrant wasrequired to file such reports), and (2) has been subject to such filingrequirements for the past 90 days. Yes** **x  No o

 

Indicate by check markwhether the registrant is a large accelerated filer, an accelerated filer, anon-accelerated filer, or a smaller reporting company. See 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 x          |
|------------------------------------------------|--------|-----------------------------------|
|                                           |   |                              |
| Non-accelerated filer o                        |   | Smaller reporting  company o |
| (Do not check if a  smaller reporting company) |   |                              |

 

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

 

As of May 1,2008, 33,747,685 shares of common stock were outstanding.

 

 

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**THEEMPIRE DISTRICT ELECTRIC COMPANY**

 

**INDEX**

 
| ** **    | ** ** |                                                                                        |                                             | **PAGE** |
|---------------|------------|---------------------------------------------------------------------------------------------|--------------------------------------------------|----------|
|          |       | Forward  Looking Statements                                                                 |                                             | 3        |
|          |       |                                                                                        |                                             |     |
| Part I - |       | Financial Information:                                                                      |                                             |     |
|          |       |                                                                                        |                                             |     |
| Item 1.       |       | Financial Statements:                                                                       |                                             |     |
|          |       |                                                                                        |                                             |     |
|          |       | a.                                                                                          | Consolidated Statements of  Operations           |     | 4 |
|          |       |                                                                                        |                                             |     |   |
|          |       | b.                                                                                          | Consolidated Statements of  Comprehensive Income |     | 6 |
|          |       |                                                                                        |                                             |     |   |
|          |       | c.                                                                                          | Consolidated Balance Sheets                      |     | 7 |
|          |       |                                                                                        |                                             |     |   |
|          |       | d.                                                                                          | Consolidated Statements of  Cash Flows           |     | 9 |
|          |       |                                                                                        |                                             |     |   |
|          |       | e.                                                                                          | Notes to Consolidated Financial  Statements      |     | 10 |
|          |       |                                                                                        |                                             |     |
| Item 2.       |       | Management’s  Discussion and Analysis of Financial Condition and Results of Operations |                                             | 29       |
|          |       |                                                                                        |                                             |     |
|          |       | Executive Summary                                                                           |                                             | 29       |
|          |       |                                                                                        |                                             |     |
|          |       | Results of Operations                                                                       |                                             | 32       |
|          |       |                                                                                        |                                             |     |
|          |       | Rate Matters                                                                                |                                             | 40       |
|          |       |                                                                                        |                                             |     |
|          |       | Competition                                                                                 |                                             | 42       |
|          |       |                                                                                        |                                             |     |
|          |       | Liquidity and  Capital Resources                                                            |                                             | 44       |
|          |       |                                                                                        |                                             |     |
|          |       | Contractual  Obligations                                                                    |                                             | 48       |
|          |       |                                                                                        |                                             |     |
|          |       | Dividends                                                                                   |                                             | 48       |
|          |       |                                                                                        |                                             |     |
|          |       | Off-Balance Sheet Arrangements                                                              |                                             | 48       |
|          |       |                                                                                        |                                             |     |
|          |       | Critical Accounting Policies                                                                |                                             | 49       |
|          |       |                                                                                        |                                             |     |
|          |       | Recently Issued Accounting Standards                                                        |                                             | 49       |
|          |       |                                                                                        |                                             |     |
| Item 3.       |       | Quantitative  and Qualitative Disclosures About Market Risk                                 |                                             | 49       |
|          |       |                                                                                        |                                             |     |
| Item 4.       |       | Controls and  Procedures                                                                    |                                             | 50       |
|          |       |                                                                                        |                                             |     |
| Part II- |       | Other  Information:                                                                         |                                             |     |
|          |       |                                                                                        |                                             |     |
| Item  1.      |       | Legal  Proceedings - (none)                                                                 |                                             |     |
|          |       |                                                                                        |                                             |     |
| Item 1A.      |       | Risk  Factors                                                                               |                                             | 51       |
|          |       |                                                                                        |                                             |     |
| Item  2.      |       | Unregistered  Sales of Equity Securities and Use of Proceeds - (none)                       |                                             |     |
|          |       |                                                                                        |                                             |     |
| Item  3.      |       | Defaults  Upon Senior Securities - (none)                                                   |                                             |     |
|          |       |                                                                                        |                                             |     |
| Item 4.       |       | Submission of Matters to a Vote of Security Holders                                         |                                             | 51       |
|          |       |                                                                                        |                                             |     |
| Item  5.      |       | Other  Information                                                                          |                                             | 51       |
|          |       |                                                                                        |                                             |     |
| Item 6.       |       | Exhibits                                                                                    |                                             | 51       |
|          |       |                                                                                        |                                             |     |
|          |       | Signatures                                                                                  |                                             | 53       |

 

2

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**FORWARD LOOKING STATEMENTS**

 

Certain matters discussed inthis quarterly report are “forward-looking statements” intended to qualify forthe safe harbor from liability established by the Private Securities LitigationReform Act of 1995. Such statements address or may address future plans,objectives, expectations and events or conditions concerning various matterssuch as capital expenditures, earnings, pension and other costs, competition,litigation, our construction program, our generation plans, our financingplans, potential acquisitions, rate and other regulatory matters, liquidity andcapital resources and accounting matters. Forward-looking statements maycontain words like “anticipate,” “believe,” “expect,” “project,” “objective” orsimilar expressions to identify them as forward-looking statements. Factorsthat could cause actual results to differ materially from those currentlyanticipated in such statements include:

 

·                  the amount, terms and timing of rate reliefwe seek and related matters;

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

·                  weather, business and economic conditions andother factors which may impact sales volumes and customer growth;

·                  operation of our electric generationfacilities and electric and gas transmission and distribution systems;

·                  the costs and other impacts resulting fromnatural disasters, such as tornados and ice storms;

·                  the periodic revision of our construction andcapital expenditure plans and cost estimates;

·                  legislation;

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

·                  competition, including the energy imbalancemarket;

·                  electric utility restructuring, includingongoing federal activities and potential state activities;

·                  the impact of electric deregulation onoff-system sales;

·                  changes in accounting requirements;

·                  other circumstances affecting anticipatedrates, revenues and costs;

·                  the timing of accretion estimates, andintegration costs relating to, completed and contemplated acquisitions and theperformance of acquired businesses;

·                  matters such as the effect of changes incredit ratings on the availability and our cost of funds;

·                  interruptions or changes in our coaldelivery, gas transportation or storage agreements or arrangements;

·                  the success of efforts to invest in anddevelop new opportunities;

·                  costs and effects of legal and administrativeproceedings, settlements, investigations and claims; and

·                  our exposure to the credit risk of ourhedging counterparties.

 

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

 

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

 

3

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**PART I.  FINANCIAL INFORMATION**

 

**Item 1. Financial Statements**

 

**THEEMPIRE DISTRICT ELECTRIC COMPANY**

**CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)**

 
| ** **                                                                                                  | ** ** | **Three Months Ended**                              | ** **  |
|-------------------------------------------------------------------------------------------------------------|------------|---------------------------------------------------------------|-------------|
| ** **                                                                                                  | ** ** | **March 31,**                                            | ** **  |
| ** **                                                                                                  | ** ** | **2008**                                                      | ** **  | **2007** | ** ** |
| ** **                                                                                                  | ** ** | **(000’s except per share amounts)** | ** **  |
| **Operating  revenues:**                                                                                    |       |                                                          |        |   |   |
| Electric                                                                                                    | ** ** | **$**                                                         | **108,305** | ** ** | $ | 96,911 |   |
| Gas                                                                                                         | ** ** | **27,275**                                                    | ** **  | 27,590 |   |
| Water                                                                                                       | ** ** | **436**                                                       | ** **  | 450 |   |
| Non-regulated                                                                                               | ** ** | **930**                                                       | ** **  | 699 |   |
| ** **                                                                                                  |       | **136,946**                                                   | ** **  | 125,650 |   |
| **Operating  revenue deductions:**                                                                          |       |                                                          | ** **  |   |   |
| Fuel – Electric                                                                                        | ** ** | **31,007**                                                    | ** **  | 25,224 |   |
| Purchased power                                                                                             | ** ** | **25,935**                                                    | ** **  | 20,218 |   |
| Cost of natural  gas sold and transported                                                                   | ** ** | **17,701**                                                    | ** **  | 18,722 |   |
| Regulated –  other                                                                                     | ** ** | **17,898**                                                    | ** **  | 17,362 |   |
| Non-regulated –  other                                                                                 | ** ** | **383**                                                       | ** **  | 344 |   |
| Maintenance and  repairs                                                                                    | ** ** | **5,566**                                                     | ** **  | 10,780 |   |
| Depreciation and  amortization                                                                              | ** ** | **13,621**                                                    | ** **  | 12,698 |   |
| Provision for  income taxes                                                                                 | ** ** | **3,118**                                                     | ** **  | 1,648 |   |
| Other taxes                                                                                                 | ** ** | **7,158**                                                     | ** **  | 6,741 |   |
| ** **                                                                                                  |       | **122,387**                                                   | ** **  | 113,737 |   |
|                                                                                                        |       |                                                          | ** **  |   |   |
| **Operating  income**                                                                                       | ** ** | **14,559**                                                    | ** **  | 11,913 |   |
|                                                                                                        |       |                                                          | ** **  |   |   |
| **Other  income and (deductions):**                                                                         |       |                                                          | ** **  |   |   |
| Allowance for  equity funds used during construction                                                        | ** ** | **1,117**                                                     | ** **  | 906 |   |
| Interest income                                                                                             | ** ** | **79**                                                        | ** **  | 94 |   |
| Benefit for  other income taxes                                                                             | ** ** | **13**                                                        | ** **  | 10 |   |
| Other -  non-operating income                                                                               | ** ** | **43**                                                        | ** **  | 36 |   |
| Other -  non-operating expense                                                                              | ** ** | **(280**                                                      | **)**       | (281 | ) |
| ** **                                                                                                  |       | **972**                                                       | ** **  | 765 |   |
| **Interest  charges:**                                                                                      |       |                                                          | ** **  |   |   |
| Long-term debt                                                                                              | ** ** | **8,072**                                                     | ** **  | 6,944 |   |
| Note payable to  securitization trust                                                                       | ** ** | **1,063**                                                     | ** **  | 1,063 |   |
| Short-term debt                                                                                             | ** ** | **531**                                                       | ** **  | 1,029 |   |
| Allowance for  borrowed funds used during construction                                                      | ** ** | **(1,348**                                                    | **)**       | (1,155 | ) |
| Other                                                                                                       | ** ** | **223**                                                       | ** **  | 266 |   |
| ** **                                                                                                  |       | **8,541**                                                     | ** **  | 8,147 |   |
| **Income  from continuing operations**                                                                      | ** ** | **6,990**                                                     | ** **  | 4,531 |   |
|                                                                                                        |       |                                                          | ** **  |   |   |
| Loss from  discontinued operations, net of tax                                                              | ** ** | **—**                                                    | ** **  | (31 | ) |
|                                                                                                        |       |                                                          | ** **  |   |   |
| **Net  income**                                                                                             | ** ** | **$**                                                         | **6,990**   | ** ** | $ | 4,500 |   |
|                                                                                                        |       |                                                          | ** **  |   |   |
| Weighted average  number of common shares outstanding - basic                                               | ** ** | **33,659**                                                    | ** **  | 30,298 |   |
|                                                                                                        |       |                                                          | ** **  |   |   |
| Weighted average  number of common shares outstanding - diluted                                             | ** ** | **33,688**                                                    | ** **  | 30,318 |   |
|                                                                                                        | ** ** | ** **                                                    |        |   |   |
| Earnings from  continuing operations per weighted average share of common stock– basic and  diluted    | ** ** | **$**                                                         | **0.21**    |   | $ | 0.15 |   |
|                                                                                                        |       |                                                          |        |   |   |
| Earnings 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**                     | ** ** | **$**                                                         | **0.21**    |   | $ | 0.15 |   |
|                                                                                                        |       |                                                          |        |   |   |
| **Dividends  per share of common stock**                                                                    | ** ** | **$**                                                         | **0.32**    |   | $ | 0.32 |   |

 

*See accompanying Notes to Consolidated Financial Statements.*

 

4

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**THEEMPIRE DISTRICT ELECTRIC COMPANY**

**CONSOLIDATEDSTATEMENTS OF OPERATIONS (UNAUDITED)**

 
| ** **                                                                                                     | ** ** | **Twelve Months Ended**                             | ** **  |
|----------------------------------------------------------------------------------------------------------------|------------|---------------------------------------------------------------|-------------|
| ** **                                                                                                     | ** ** | **March 31,**                                            | ** **  |
| ** **                                                                                                     | ** ** | **2008**                                                      | ** **  | **2007** | ** ** |
| ** **                                                                                                     | ** ** | **(000’s except per share amounts)** | ** **  |
| **Operating  revenues:**                                                                                       |       |                                                          |        |   |   |
| Electric                                                                                                       | ** ** | **$**                                                         | **436,554** |   | $ | 396,845 |   |
| Gas                                                                                                            | ** ** | **59,563**                                                    |        | 52,735 |   |
| Water                                                                                                          | ** ** | **1,865**                                                     |        | 1,924 |   |
| Non-regulated                                                                                                  | ** ** | **3,474**                                                     |        | 2,657 |   |
| ** **                                                                                                     |       | **501,456**                                                   |        | 454,161 |   |
| **Operating  revenue deductions:**                                                                             |       |                                                          |        |   |   |
| Fuel - Electric                                                                                                | ** ** | **119,342**                                                   |        | 98,300 |   |
| Purchased power                                                                                                | ** ** | **83,388**                                                    |        | 66,630 |   |
| Cost of natural  gas sold and transported                                                                      | ** ** | **36,605**                                                    |        | 34,007 |   |
| Regulated –  other                                                                                        | ** ** | **71,902**                                                    |        | 64,584 |   |
| Non-regulated –  other                                                                                    | ** ** | **1,650**                                                     |        | 1,372 |   |
| Maintenance and  repairs                                                                                       | ** ** | **26,846**                                                    |        | 28,719 |   |
| Loss on plant  disallowance                                                                                    | ** ** | **—**                                                    |        | 828 |   |
| Gain on sale of  assets                                                                                        | ** ** | **(1,241**                                                    | **)**       | **—** | ** ** |
| Depreciation and  amortization                                                                                 | ** ** | **53,523**                                                    |        | 41,896 |   |
| Provision for  income taxes                                                                                    | ** ** | **15,885**                                                    |        | 22,432 |   |
| Other taxes                                                                                                    | ** ** | **25,344**                                                    |        | 22,983 |   |
| ** **                                                                                                     |       | **433,244**                                                   |        | 381,751 |   |
|                                                                                                           |       |                                                          |        |   |   |
| **Operating  income**                                                                                          | ** ** | **68,212**                                                    |        | 72,410 |   |
|                                                                                                           |       |                                                          |        |   |   |
| **Other  income and (deductions):**                                                                            |       |                                                          |        |   |   |
| Allowance for  equity funds used during construction                                                           | ** ** | **3,135**                                                     |        | 2,186 |   |
| Interest income                                                                                                | ** ** | **312**                                                       |        | 396 |   |
| Benefit/(provision)  for other income taxes                                                                    | ** ** | **(25**                                                       | **)**       | 3 |   |
| Other -  non-operating income                                                                                  | ** ** | **153**                                                       |        | 51 |   |
| Other -  non-operating expense                                                                                 | ** ** | **(1,116**                                                    | **)**       | (1,053 | ) |
| ** **                                                                                                     |       | **2,459**                                                     |        | 1,583 |   |
| **Interest  charges:**                                                                                         |       |                                                          |        |   |   |
| Long-term debt                                                                                                 | ** ** | **32,249**                                                    |        | 26,953 |   |
| Note payable to  securitization trust                                                                          | ** ** | **4,250**                                                     |        | 4,250 |   |
| Short-term debt                                                                                                | ** ** | **2,443**                                                     |        | 2,929 |   |
| Allowance for  borrowed funds used during construction                                                         | ** ** | **(4,936**                                                    | **)**       | (3,620 | ) |
| Other                                                                                                          | ** ** | **1,026**                                                     |        | 1,036 |   |
| ** **                                                                                                     |       | **35,032**                                                    |        | 31,548 |   |
| **Income  from continuing operations**                                                                         | ** ** | **35,639**                                                    |        | 42,445 |   |
|                                                                                                           |       |                                                          |        |   |   |
| Income/(loss)  from discontinued operations, net of tax                                                        | ** ** | **94**                                                        |        | (277 | ) |
|                                                                                                           |       |                                                          |        |   |   |
| **Net  income**                                                                                                | ** ** | **$**                                                         | **35,733**  |   | $ | 42,168 |   |
|                                                                                                           |       |                                                          |        |   |   |
| Weighted average  number of common shares outstanding - basic                                                  | ** ** | **31,422**                                                    |        | 29,303 |   |
|                                                                                                           |       |                                                          |        |   |   |
| Weighted average  number of common shares outstanding – diluted                                           | ** ** | **31,449**                                                    |        | 29,316 |   |
|                                                                                                           |       |                                                          |        |   |   |
| Earnings from  continuing operations per weighted average share of common stock– basic and  diluted       | ** ** | **$**                                                         | **1.14**    |   | $ | 1.45 |   |
|                                                                                                           |       |                                                          |        |   |   |
| Income/loss from  discontinued operations per weighted average share of common stock – basic  and diluted | ** ** | **$**                                                         | **0.00**    |   | $ | (0.01 | ) |
|                                                                                                           |       |                                                          |        |   |   |
| **Total  earnings per weighted average share of common stock – basic and diluted**                        | ** ** | **$**                                                         | **1.14**    |   | $ | 1.44 |   |
|                                                                                                           |       |                                                          |        |   |   |
| **Dividends  per share of common stock**                                                                       | ** ** | **$**                                                         | **1.28**    |   | $ | 1.28 |   |

 

*See accompanying Notes to Consolidated Financial Statements.*

 

5

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**THEEMPIRE DISTRICT ELECTRIC COMPANY**

**CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME(UNAUDITED)**

** **
| ** **                                                                                                             | ** ** | **Three Months Ended** | ** ** |
|------------------------------------------------------------------------------------------------------------------------|------------|----------------------------------|------------|
| ** **                                                                                                             | ** ** | **March 31,**               | ** ** |
| ** **                                                                                                             | ** ** | **2008**                         | ** ** | **2007** | ** ** |
| ** **                                                                                                             | ** ** | **($-000’s)**               | ** ** |
|                                                                                                                   |       |                             |       |   |   |
| **Net  income**                                                                                                        | ** ** | **$**                            | **6,990**  |   | $ | 4,500 |   |
| Reclassification  adjustments for (gain)/loss included in net income or reclassified to  regulatory asset or liability |       | **(860**                         | **)**      | 164 |   |
| Net change in  fair value of open derivative contracts for period                                                      | ** ** | **11,023**                       |       | 2,881 |   |
| Income taxes                                                                                                           | ** ** | **(3,872**                       | **)**      | (1,160 | ) |
| Net change in unrealized  gain on derivative contracts                                                                 | ** ** | **6,291**                        |       | 1,885 |   |
|                                                                                                                   |       |                             |       |   |   |
| **Comprehensive  income**                                                                                              | ** ** | **$**                            | **13,281** |   | $ | 6,385 |   |

** **
| ** **                                                                                                       | ** ** | **Twelve Months Ended** | ** ** |
|------------------------------------------------------------------------------------------------------------------|------------|-----------------------------------|------------|
| ** **                                                                                                       | ** ** | **March 31,**                | ** ** |
| ** **                                                                                                       | ** ** | **2008**                          | ** ** | **2007** | ** ** |
| ** **                                                                                                       | ** ** | **($-000’s)**                | ** ** |
|                                                                                                             |       |                              |       |   |   |
| **Net  income**                                                                                                  | ** ** | **$**                             | **35,733** |   | $ | 42,168 |   |
| Reclassification  adjustments for gains included in net income or reclassified to regulatory  asset or liability |       | **(2,633**                        | **)**      | (219 | ) |
| Net change in  fair value of open derivative contracts for period                                                | ** ** | **13,370**                        |       | (4,699 | ) |
| Income taxes                                                                                                     | ** ** | **(4,091**                        | **)**      | 1,874 |   |
| Net change in  unrealized gain/(loss) on derivative contracts                                                    | ** ** | **6,646**                         |       | (3,044 | ) |
|                                                                                                             |       |                              |       |   |   |
| **Comprehensive  income**                                                                                        | ** ** | **$**                             | **42,379** |   | $ | 39,124 |   |

 

*Seeaccompanying Notes to Consolidated Financial Statements*****

 

6

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**THEEMPIRE DISTRICT ELECTRIC COMPANY**

**CONSOLIDATED BALANCE SHEETS(UNAUDITED)**

 
| ** **                                            | ** ** | **March 31, 2008** | ** ** | **December 31, 2007** | ** ** |
|-------------------------------------------------------|------------|------------------------------|------------|---------------------------------|------------|
| ** **                                            | ** ** | **($-000’s)**           | ** ** |
| **Assets**                                            |       |                         |       |                            |       |
| Plant and property, at original cost:                 |       |                         |       |                            |       |
| Electric                                              |       | $                            | 1,455,620  |                            | $          | 1,409,217 |   |
| Natural gas                                           |       | 54,982                       |       | 54,715                          |       |
| Water                                                 |       | 10,415                       |       | 10,353                          |       |
| Non-regulated                                         |       | 26,620                       |       | 26,355                          |       |
| Construction work in progress                         |       | 173,448                      |       | 167,049                         |       |
|                                                  |       | 1,721,085                    |       | 1,667,689                       |       |
| Accumulated depreciation and amortization             |       | 498,765                      |       | 488,816                         |       |
|                                                  |       | 1,222,320                    |       | 1,178,873                       |       |
|                                                  |       |                         |       |                            |       |
| **Current assets:**                                   |       |                         |       |                            |       |
| Cash and cash equivalents                             |       | 4,581                        |       | 4,043                           |       |
| Accounts receivable – trade, net                 |       | 42,927                       |       | 38,011                          |       |
| Accrued unbilled revenues                             |       | 15,751                       |       | 20,886                          |       |
| Accounts receivable – other                      |       | 10,616                       |       | 15,465                          |       |
| Fuel, materials and supplies                          |       | 42,578                       |       | 49,482                          |       |
| Unrealized gain in fair value of derivative contracts |       | 8,677                        |       | 2,499                           |       |
| Prepaid expenses                                      |       | 2,503                        |       | 3,308                           |       |
|                                                  |       | 127,633                      |       | 133,694                         |       |
| **Noncurrent assets and deferred charges:**           |       |                         |       |                            |       |
| Regulatory assets                                     |       | 92,720                       |       | 92,785                          |       |
| Goodwill                                              |       | 39,492                       |       | 39,492                          |       |
| Unamortized debt issuance costs                       |       | 8,681                        |       | 6,662                           |       |
| Unrealized gain in fair value of derivative contracts |       | 20,121                       |       | 17,520                          |       |
| Other                                                 |       | 4,021                        |       | 4,048                           |       |
|                                                  |       | 165,035                      |       | 160,507                         |       |
| **Total Assets**                                      |       | $                            | 1,514,988  |                            | $          | 1,473,074 |   |

 

*Seeaccompanying Notes to Consolidated Financial Statements*****

 

7

----

 
| ** **                                                                                         | ** ** | **March 31, 2008** | ** ** | **December 31, 2007** | ** ** |
|----------------------------------------------------------------------------------------------------|------------|------------------------------|------------|---------------------------------|------------|
| ** **                                                                                         | ** ** | **($-000’s)**           | ** ** |
| **Capitalization and Liabilities**                                                                 |       |                         |       |                            |       |
| Common stock, $1 par value, 33,726,053 and 33,605,871 shares issued and  outstanding, respectively |       | $                            | 33,726     |                            | $          | 33,606 |   |
| Capital in excess of par value                                                                     |       | 479,960                      |       | 477,385                         |       |
| Retained earnings                                                                                  |       | 13,373                       |       | 17,153                          |       |
| Accumulated other comprehensive income, net of income tax                                          |       | 17,323                       |       | 11,032                          |       |
| **Total common stockholders’ equity**                                                         |       | 544,382                      |       | 539,176                         |       |
|                                                                                               |       |                         |       |                            |       |
| **Long-term debt:**                                                                                |       |                         |       |                            |       |
| Note payable to securitization trust                                                               |       | 50,000                       |       | 50,000                          |       |
| Obligations under capital lease                                                                    |       | 306                          |       | 349                             |       |
| First mortgage bonds and secured debt                                                              |       | 242,970                      |       | 242,959                         |       |
| Unsecured debt                                                                                     |       | 248,549                      |       | 248,572                         |       |
| **Total long-term debt**                                                                           |       | 541,825                      |       | 541,880                         |       |
| **Total long-term debt and common stockholders’ equity**                                      |       | 1,086,207                    |       | 1,081,056                       |       |
|                                                                                               |       |                         |       |                            |       |
| **Current liabilities:**                                                                           |       |                         |       |                            |       |
| Accounts payable and accrued liabilities                                                           |       | 54,878                       |       | 79,282                          |       |
| Current maturities of long-term debt                                                               |       | 153                          |       | 150                             |       |
| Short-term debt                                                                                    |       | 74,225                       |       | 33,040                          |       |
| Customer deposits                                                                                  |       | 8,675                        |       | 8,414                           |       |
| Interest accrued                                                                                   |       | 10,810                       |       | 5,147                           |       |
| Unrealized loss in fair value of derivative contracts                                              |       | 1,172                        |       | 1,611                           |       |
| Taxes accrued                                                                                      |       | 9,235                        |       | 2,931                           |       |
| Other current liabilities                                                                          |       | 2,941                        |       | 328                             |       |
|                                                                                               |       | 162,089                      |       | 130,903                         |       |
| **Commitments and contingencies (Note 7)**                                                         |       |                         |       |                            |       |
| **Noncurrent liabilities and deferred credits:**                                                   |       |                         |       |                            |       |
| Regulatory liabilities                                                                             |       | 61,681                       |       | 58,107                          |       |
| Deferred income taxes                                                                              |       | 167,813                      |       | 165,989                         |       |
| Unamortized investment tax credits                                                                 |       | 3,361                        |       | 3,441                           |       |
| Pension and other postretirement benefit obligations                                               |       | 14,496                       |       | 14,115                          |       |
| Unrealized loss in fair value of derivative contracts                                              |       | —                       |       | 698                             |       |
| Other                                                                                              |       | 19,341                       |       | 18,765                          |       |
|                                                                                               |       | 266,692                      |       | 261,115                         |       |
| **Total Capitalization and Liabilities**                                                           |       | $                            | 1,514,988  |                            | $          | 1,473,074 |   |

 

*Seeaccompanying Notes to Consolidated Financial Statements*

 

8

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**THEEMPIRE DISTRICT ELECTRIC COMPANY**

**CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)**

 
| ** **                                                                    | ** ** | **Three Months Ended** | ** ** |
|-------------------------------------------------------------------------------|------------|----------------------------------|------------|
| ** **                                                                    | ** ** | **March 31,**               | ** ** |
| ** **                                                                    | ** ** | **2008**                         | ** ** | **2007** | ** ** |
| ** **                                                                    | ** ** | **($-000’s)**               | ** ** |
| **Operating  activities:**                                                    |       |                             |       |   |   |
| Net income                                                                    |       | $                                | 6,990      |   | $ | 4,500 |   |
| Adjustments to  reconcile net income to cash flows from operating activities: |       |                             |       |   |   |
| Depreciation and  amortization                                                |       | 14,558                           |       | 14,454 |   |
| Pension and  other postretirement benefit costs                               |       | 2,465                            |       | 2,141 |   |
| Deferred income  taxes and unamortized investment tax credit, net             |       | (318                             | )          | (452 | ) |
| Allowance for  equity funds used during construction                          |       | (1,117                           | )          | (906 | ) |
| Stock  compensation expense                                                   |       | 1,009                            |       | 838 |   |
| Non-cash  (gain)/loss on derivatives                                          |       | (57                              | )          | 274 |   |
| Cash flows  impacted by changes in:                                           |       |                             |       |   |   |
| Accounts  receivable and accrued unbilled revenues                            |       | 5,497                            |       | (114 | ) |
| Fuel, materials  and supplies                                                 |       | 6,903                            |       | 1,564 |   |
| Prepaid  expenses, other current assets and deferred charges                  |       | 99                               |       | (3,694 | ) |
| Accounts payable  and accrued liabilities                                     |       | (18,115                          | )          | (3,396 | ) |
| Interest, taxes  accrued and customer deposits                                |       | 12,283                           |       | 9,807 |   |
| Other  liabilities and other deferred credits                                 |       | 1,861                            |       | 211 |   |
|                                                                          |       |                             |       |   |   |
| Net cash  provided by operating activities of continuing operations           |       | 32,058                           |       | 25,227 |   |
| Net cash  provided by operating activities of discontinued operations         |       | —                           |       | 71 |   |
| **Net  cash provided by operating activities**                                |       | 32,058                           |       | 25,298 |   |
|                                                                          |       |                             |       |   |   |
| **Investing  activities:**                                                    |       |                             |       |   |   |
| Capital  expenditures – regulated                                        |       | (60,961                          | )          | (47,954 | ) |
| Capital  expenditures and other investments – non-regulated              |       | (429                             | )          | (664 | ) |
| Proceeds from  the sale of non-regulated business                             |       | —                           |       | 2,500 |   |
|                                                                          |       |                             |       |   |   |
| Net cash used in  investing activities of continuing operations               |       | (61,390                          | )          | (46,118 | ) |
| Net cash  provided by investing activities of discontinued operations         |       | —                           |       | 2 |   |
| **Net  cash used in investing activities**                                    |       | (61,390                          | )          | (46,116 | ) |
|                                                                          |       |                             |       |   |   |
| **Financing  activities:**                                                    |       |                             |       |   |   |
| Proceeds from  first mortgage bonds                                           |       | —                           |       | 79,831 |   |
| Debt financing  costs                                                         |       | (2,152                           | )          | — |   |
| Long-term debt  issuance costs                                                |       | —                           |       | (910 | ) |
| Proceeds from  issuance of common stock net of issuance costs                 |       | 1,688                            |       | 1,338 |   |
| Net short-term  (repayments)/borrowings                                       |       | 41,185                           |       | (37,300 | ) |
| Dividends                                                                     |       | (10,770                          | )          | (9,695 | ) |
| Other                                                                         |       | (81                              | )          | (135 | ) |
|                                                                          |       |                             |       |   |   |
| Net cash  provided by financing activities of continuing operations           |       | 29,870                           |       | 33,129 |   |
| Net cash (used  in) financing activities of discontinued operations           |       | —                           |       | (22 | ) |
| **Net  cash provided by financing activities**                                |       | 29,870                           |       | 33,107 |   |
|                                                                          |       |                             |       |   |   |
| **Net  increase in cash and cash equivalents**                                |       | 538                              |       | 12,289 |   |
|                                                                          |       |                             |       |   |   |
| **Cash  and cash equivalents at beginning of period**                         |       | 4,043                            |       | 12,303 |   |
|                                                                          |       |                             |       |   |   |
| **Cash  and cash equivalents at end of period**                               |       | $                                | 4,581      |   | $ | 24,592 |   |

 

*See accompanying Notes to Consolidated Financial Statements.*

 

9

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**NOTES TO CONSOLIDATED FINANCIALSTATEMENTS (UNAUDITED)**

 

**Note 1- Summary of Significant Accounting Policies**

 

We operate our businesses asthree segments:  electric, gas and other.The Empire District Electric Company (EDE), a Kansas corporation organized in1909, 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 providewater service to three towns in Missouri. The Empire District Gas Company (EDG)is our wholly-owned subsidiary formed to hold the Missouri Gas assets acquiredfrom Aquila, Inc. on June 1, 2006. It provides natural gasdistribution to communities in northwest, north central and west centralMissouri. Our other segment primarily consists of a 100% interest in EmpireDistrict Industries Inc., a subsidiary for our fiber optics business. Thesebusinesses are held by our wholly-owned subsidiary, EDE Holdings, Inc.(EDE Holdings).

 

Theaccompanying interim financial statements do not include all disclosuresincluded in the annual financial statements and therefore should be read inconjunction with the financial statements and notes thereto included in ourAnnual Report on Form 10-K for the fiscal year ended December 31,2007.

 

The information furnished reflects all adjustments, consisting only ofnormal recurring adjustments, which are in our opinion necessary to statefairly the results for the interim periods as well as present these periods ona consistent basis with the financial statements for the fiscal year ended December 31,2007. Certain reclassifications have been made to prior year information toconform to the current year presentation.

 

**Note 2- Recently Issued Accounting Standards**

 

On September 15, 2006,Statement of Financial Accounting Standards (SFAS) No. 157, “Fair ValueMeasurements,” (FAS 157) was issued. We adopted this statement on January 1,2008. See Note 13 for the discussion of this adoption and the effect of FASBStaff Position (FSP) 157-2 which amended FAS 157 to delay the effective datefor all non-financial assets and liabilities.

 

On February 15, 2007,the Financial Accounting Standards Board (FASB) issued SFAS No. 159, “TheFair-Value Option for Financial Assets and Financial Liabilities – including anamendment of FAS 115” (FAS 159). Under FAS 159, a company may elect to measureeligible financial assets and financial liabilities at fair value. Unrealizedgains and losses on items for which the fair value option has been elected arereported in earnings at each subsequent reporting date. FAS 159 is effectivefor financial statements issued for fiscal years beginning after November 15,2007. FAS 159 had no effect on our financial statements.

 

OnApril 30, 2007, the FASB issued FASB Staff Position No. 39-1 (FIN39), an “Amendment of FASB Interpretation No. 39”. FIN 39 is effective forfiscal years ending after November 15, 2007. It amends paragraph 3 ofInterpretation 39 to replace the terms “conditional contracts and exchangecontracts” with the term “derivative instruments as defined in FASB Statement No. 133,Accounting for Derivative Instruments and Hedging Activities”. It also amendsparagraph 10 of Interpretation 39 to permit a reporting entity to offset fairvalue amounts recognized for the right to reclaim cash collateral (areceivable) or the obligation to return cash collateral (a payable) againstfair value amounts recognized for derivative instruments executed with the samecounterparty under the same master netting arrangement that have been offset inaccordance with that paragraph. We currently do not apply this offsettingalternative.

 

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 ofARB No. 51” (FAS 160). FAS 141(R) and FAS 160 are effective forbusiness combinations entered into in fiscal years beginning on or after December 15,2008. FAS 141(R) changes the definitions of a business and a businesscombination, and will result in more transactions recorded as businesscombinations. Certain acquired contingencies will be recorded

 

10

----

 

initiallyat fair value on the acquisition date, transactions and restructuring costsgenerally will be expensed as incurred and in partial acquisitions, companiesgenerally will record 100 percent of the assets and liabilities at fair value,including goodwill.

 

In April 2008, the FASBissued SFAS 161 “Disclosure About Derivative Instruments and HedgingActivities, an Amendment of FASB Statement No. 133” (FAS 161). FAS 161enhances the current disclosure framework in FAS 133, “Accounting forDerivative Instruments and Hedging Activities.” FAS 161 is effective forperiods beginning after November 15, 2008. We do not expect the adoptionof FAS 161 to have a material effect on our financial statement disclosures.

 

See Note 1 under “Notes toConsolidated Financial Statements” in our Annual Report on Form 10-K forthe year ended December 31, 2007 for further information regardingrecently issued accounting standards.

 

**Note 3– Regulatory Matters**

 

Thefollowing table sets forth the components of our regulatory assets andliabilities on our consolidated balance sheet.

 

**Regulatory Assets and Liabilities**

** **
| **(In thousands)**                        | ** ** | **March 31, 2008** | ** ** | **December 31, 2007** | ** ** |
|------------------------------------------------|------------|------------------------------|------------|---------------------------------|------------|
| **Regulatory  Assets:**                        |       |                         |       |                            |       |
| Income taxes                                   |       | $                            | 31,577     |                            | $          | 30,947 |   |
| Unamortized loss  on reacquired debt           |       | 14,482                       |       | 14,813                          |       |
| Unamortized loss  on interest rate derivative  |       | 2,642                        |       | 2,719                           |       |
| Asbury five-year  maintenance                  |       | 2,119                        |       | 2,054                           |       |
| Pension and  other postretirement benefits (1) |       | 21,849                       |       | 22,760                          |       |
| Ice storm costs                                |       | 15,594                       |       | 15,518                          |       |
| Asset retirement  obligation                   |       | 3,006                        |       | 2,971                           |       |
| Other                                          |       | 1,451                        |       | 1,003                           |       |
| **Total**                                      |       | $                            | 92,720     |                            | $          | 92,785 |   |

** **
| **(In thousands)**                                   | ** ** | **March 31, 2008** | ** ** | **December 31, 2007** | ** ** |
|-----------------------------------------------------------|------------|------------------------------|------------|---------------------------------|------------|
| **Regulatory  Liabilities:**                              |       |                         |       |                            |       |
| Income taxes                                              |       | $                            | 11,096     |                            | $          | 11,214 |   |
| Unamortized gain  on interest rate derivative             |       | 4,349                        |       | 4,391                           |       |
| Gain on disposition  of emission allowances               |       | 287                          |       | 328                             |       |
| Cost of removal                                           |       | 36,894                       |       | 35,724                          |       |
| Unrecovered  purchased gas costs and Kansas fuel costs(2) |       | 2,776                        |       | 1,324                           |       |
| Pensions and  other postretirement benefits(3)            |       | 6,279                        |       | 5,126                           |       |
| **Total**                                                 |       | $                            | 61,681     |                            | $          | 58,107 |   |

 

----

(1) Primarily reflects regulatory assetsresulting from the adoption of FAS 158 and regulatory accounting for EDGacquisition costs.

(2) Includes the effects of the PGA clauserelated to our gas segment and the over recovery of Kansas fuel costs.

(3) Includes the effect of costs incurredthat are more or less than those allowed in rates for the Missouri (EDE andEDG) and Kansas (EDE) portion of pension costs and the Missouri EDE portion ofother postretirement benefit costs. Since January 1, 2008, approximately$1.2 million in additional regulatory liabilities and corresponding expenseincreases have been recognized.

 

**Note 4–Acquisition of Missouri Natural Gas Distribution Operations**

 

On September 21, 2005,we announced that we had entered into an Asset Purchase Agreement pursuant towhich we agreed to acquire the Missouri natural gas distribution operations ofAquila, Inc. This acquisition was completed by our wholly-ownedsubsidiary, The Empire District 

 

11

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GasCompany (EDG), on June 1, 2006. This transaction was subject to theapproval of the MPSC, which was obtained, effective May 1, 2006. The totalpurchase price, including working capital and net plant adjustments butexcluding acquisition costs, was $102.5 million. We recorded $39.5 million ofgoodwill as a result of the acquisition. All of this goodwill is expected to betax deductible.

 

**The components of thepurchase price allocation for the Missouri Gas acquisition are shown below.Assets and liabilities are valued at fair value. In the case of property, plantand equipment, fair value is calculated in a manner consistent with the amountrecoverable for regulatory treatment.**

** **
| **(In thousands)**            | ** ** | **Missouri Gas** | ** ** |
|------------------------------------|------------|-----------------------|------------|
| **Purchase  Price:**               |       |                  |       |
| **Cash  paid**                     |       | $                     | 102,502    |   |
| **Acquisition  costs**             |       | 2,447                 |       |
| **Total**                          |       | $                     | 104,949    |   |
|                               |       |                  |       |
| **Allocation:**                    |       |                  |       |
| **Property,  plant and equipment** |       | $                     | 52,226     |   |
| **Current  assets**                |       | 15,292                |       |
| **Goodwill**                       |       | 39,492                |       |
| **Other  assets**                  |       | 11,082                |       |
| **Other  liabilities**             |       | (13,143               | )          |
| **Total**                          |       | $                     | 104,949    |   |

 

Thefollowing presents certain consolidated proforma financial information for thetwelve months ended March 31, 2007 as if our acquisition of Missouri Gashad been completed as of April 1, 2006. These estimates are based onhistorical results of the Missouri Gas operations, provided to us by Aquila, Inc.,and are unaudited.

 
| **($-000’s except per share  amounts)**                                | ** ** | **Twelve Months Ended  March 31, 2007** | ** ** |
|-----------------------------------------------------------------------------|------------|-------------------------------------------------------------|------------|
| Proforma  revenues                                                          |       | $                                                           | 459,322    |   |
|                                                                        |       |                                                        |       |
| Proforma net  income from continuing operations                             |       | $                                                           | 42,248     |   |
|                                                                        |       |                                                        |       |
| Proforma  earnings per share from continuing operations - basic and diluted |       | $                                                           | 1.41       |   |

 

**Note 5– Risk Management andDerivative Financial Instruments**

 

Weutilize derivatives to help manage our natural gas commodity market riskresulting from purchasing natural gas, to be used as fuel in our electricbusiness and for sale in our natural gas business, on the volatile spot marketand to manage certain interest rate exposure.

 

Asof March 31, 2008 and December 31, 2007, we have recorded thefollowing assets and liabilities representing the fair value of derivativefinancial instruments, (in thousands):

 

**ASSET DERIVATIVES**

 
| ** **                                                             | ** ** | ** **                                 | ** ** | **March 31,**  | ** ** | **December 31,** | ** ** |
|------------------------------------------------------------------------|------------|--------------------------------------------|------------|---------------------|------------|-----------------------|------------|
| **Derivatives designated as hedging **             | ** ** | **2008**                                   | ** ** | **2007**            | ** ** |
| **instruments under FAS 133****(1)**                    | ** ** | **Balance Sheet Classification** | ** ** | **Fair Value** | ** ** | **Fair Value**   | ** ** |
| Natural gas  contracts, electric segment                               |       | Current assets                             |       | $                   | 8,677      |                  | $          | 2,435 |   |
|                                                                   |       | Non-current assets and deferred charges    |       | 20,121              |       | 17,520                |       |
|                                                                   |       |                                       |       |                |       |                  |       |
| **Derivatives not designated as  hedging   instruments under FAS 133** | ** ** | ** **                                 | ** ** | ** **          | ** ** | ** **            | ** ** |
| Natural gas  contracts, gas segment                                    |       | Current assets                             |       | —              |       | 64                    |       |
| **Total  derivatives assets**                                          | ** ** | ** **                                 | ** ** | **$**               | **28,798** | ** **            | **$**      | **20,019** | ** ** |

 

----

(1)Statement of Financial Accounting Standards (SFAS)**No. 133 “Accounting forDerivative Instruments and Hedging Activities” (FAS 133).**

 

12

----

 

**LIABILITY DERIVATIVES**

 
| ** **                                                                             | ** ** | ** **                                   | ** ** | **March 31,**  | ** ** | **December 31,** | ** ** |
|----------------------------------------------------------------------------------------|------------|----------------------------------------------|------------|---------------------|------------|-----------------------|------------|
| **Derivatives designated as hedging instruments under ** | ** ** | **2008**                                     | ** ** | **2007**            | ** ** |
| **FAS 133**                                                                       | ** ** | **Balance Sheet Classification**   | ** ** | **Fair Value** | ** ** | **Fair Value**   | ** ** |
| Natural gas  contracts, electric segment                                               |       | Current liabilities                          |       | $                   | 1,172      |                  | $          | 1,154 |   |
|                                                                                   |       | Non-current liabilities and deferred charges |       | —              |       | 698                   |       |
|                                                                                   |       |                                         |       |                |       |                  |       |
| **Derivatives not designated as  hedging instruments   under FAS 133**                 | ** ** | ** **                                   | ** ** | ** **          | ** ** | ** **            | ** ** |
| Natural gas  contracts, gas segment                                                    |       | Current liabilities                          |       | $                   | —     |                  | $          | 457 |   |
| **Total derivatives  liabilities**                                                     | ** ** | ** **                                   | ** ** | **$**               | **1,172**  | ** **            | **$**      | **2,309** | ** ** |

 

**ACCUMULATED OTHER COMPREHENSIVE INCOME - ELECTRIC SEGMENT**

 
| ** **                                                               | ** ** | ** **                                   | ** ** | **March 31,**  | ** ** | **December 31,** | ** ** |
|--------------------------------------------------------------------------|------------|----------------------------------------------|------------|---------------------|------------|-----------------------|------------|
| ** **                                                               | ** ** | **2008**                                     | ** ** | **2007**            | ** ** |
| ** **                                                               | ** ** | **Balance Sheet Classification**   | ** ** | **Fair Value** | ** ** | **Fair Value**   | ** ** |
| Current assets -  Electric segment                                       |       | Current assets                               |       | $                   | 8,677      |                  | $          | 2,435 |   |
| Settled futures  contracts in margin account                             |       | Current assets                               |       | 335                 |       | —                |       |
| Swap settled in  accounts receivable derivatives                         |       | Current assets                               |       | 37                  |       | —                |       |
| Ineffective  non-hedged unrealized gain included in current assets above |       | Current assets                               |       | (13                 | )          | (281                  | )          |
| Non-current  assets - Electric segment                                   |       | Non-current assets and deferred charges      |       | 20,121              |       | 17,520                |       |
| Current  liabilities - Electric segment                                  |       | Current liabilities                          |       | (1,172              | )          | (1,154                | )          |
| Non-current  liabilities - Electric segment                              |       | Non-current liabilities and deferred charges |       |                |       | (698                  | )          |
| Net fair value  of derivatives (before tax) – Electric segment      |       |                                         |       | 27,985              |       | 17,822                |       |
| Tax effect                                                               |       | Deferred taxes                               |       | (10,662             | )          | (6,790                | )          |
| **Accumulated  other comprehensive income - Electric segment**           |       | Capitalization                               | ** ** | **$**               | **17,323** | ** **            | **$**      | **11,032** | ** ** |

 

*Electric*

 

A$17.3 million net of tax, unrealized gain representing the fair market value ofour electric segment derivative contracts treated as cash flow hedges isrecognized as Accumulated Other Comprehensive Income in the capitalizationsection of the balance sheet as of March 31, 2008. The tax effect of $10.7million on this gain is included in deferred taxes. These amounts will beadjusted cumulatively on a monthly basis during the determination periods,beginning April 1, 2008 and ending on September 30, 2011. At the endof each determination period, or if cash flow hedge treatment is discontinued,any gain or loss for that period related to the instrument will be reclassifiedto fuel expense. As of March 31, 2008, approximately $7.9 million ofunrealized gains are applicable to financial instruments which will settlewithin the next twelve months.

 

Thefollowing table sets forth the actual pre-tax gains/(losses) from the qualifiedportion of our hedging activities for settled contracts for the electricsegment for each of the periods ended March 31, (in thousands):

** **
| **Derivatives in FAS 133 Cash Flow  Hedging Relationships** | ** ** | **Income Statement  Classification of  Gain / (Loss) on   Derivative** | ** ** | **Amount of Gain / (Loss) Reclassed from OCI into  Income -(Effective portion) ** | ** ** |
|-------------------------------------------------------------------------------------------|------------|------------------------------------------------------------------------------------------------------|------------|------------------------------------------------------------------------------------------------------------------------------------------|------------|
| ** **                                                                                | ** ** | ** **                                                                                           | ** ** | **Three Months Ended **                                                                                                   | ** ** | **Twelve Months Ended** | ** ** |
| ** **                                                                                | ** ** | ** **                                                                                           | ** ** | **2008**                                                                                                                                 | ** ** | **2007** | ** ** | **2008** | ** ** | **2007** | ** ** |
| Commodity  contracts – electric segment                                              |       | Fuel Expense                                                                                         |       | $                                                                                                                                        | 860        |   | $ | (143 | ) | $ | 2,633 |   | $ | 241 |   |
|                                                                                      |       |                                                                                                 |       |                                                                                                                                     |       |   |   |   |   |   |   |
| **Total  Effective - Electric Segment**                                                   | ** ** | ** **                                                                                           | ** ** | **$**                                                                                                                                    | **860**    | ** ** | **$** | **(143** | **)** | **$** | **2,633** | ** ** | **$** | **241** | ** ** |

 

Werecord unrealized gains/(losses) on the ineffective portion of our gas hedgingactivities in “Fuel” under the Operating Revenue Deductions section of ourstatement of operations since all of our gas hedging activities are related tostabilizing fuel costs as part of our fuel procurement program and are notspeculative activities.

 

13

----

 

Thefollowing table sets forth “mark-to-market” pre-tax gains/ (losses) from the ineffectiveportion of our hedging activities for the electric segment for each of theperiods ended March 31, (in thousands):

 
| **Derivatives in FAS 133 Cash Flow  Hedging Relationships** | ** ** | **Income  Statement  Classification of  Gain / (Loss) on  Derivative** | ** ** | **Amount of Gain / (Loss) Recognized in Income on  Derivative-(Ineffective) ** | ** ** |
|-------------------------------------------------------------------------------------------|------------|--------------------------------------------------------------------------------------------|------------|-----------------------------------------------------------------------------------------------------------------------------|------------|
| ** **                                                                                | ** ** | ** **                                                                                 | ** ** | **Three Months Ended **                                                                                      | ** ** | **Twelve Months Ended** | ** ** |
| ** **                                                                                | ** ** | ** **                                                                                 | ** ** | **2008**                                                                                                                    | ** ** | **2007** | ** ** | **2008** | ** ** | **2007** | ** ** |
| Commodity  contracts – electric segment                                              |       | Fuel Expense                                                                               |       | $                                                                                                                           | 34         |   | $ | (30 | ) | $ | 353 |   | $ | (30 | ) |
|                                                                                      |       |                                                                                       |       |                                                                                                                        |       |   |   |   |   |   |   |
| **Total  Ineffective - Electric Segment**                                                 | ** ** | ** **                                                                                 | ** ** | **$**                                                                                                                       | **34**     | ** ** | **$** | **(30** | **)** | **$** | **353** | ** ** | **$** | **(30** | **)** |

 

Thefollowing table sets forth “mark-to-market” pre-tax gains/ (losses) fromderivatives not designated as hedging instruments under FAS 133 for theelectric segment for each of the periods ended March 31, (in thousands):

** **
| **Derivatives Not Designated as  Hedging Instruments Under FAS 133(1)** | ** ** | **Income  Statement  Classification of  Gain / (Loss) on  Derivative** | ** ** | **Amount of Gain / (Loss) Recognized in Income  on Derivative ** | ** ** |
|------------------------------------------------------------------------------------------------------------|------------|--------------------------------------------------------------------------------------------|------------|---------------------------------------------------------------------------------------------------------------|------------|
| ** **                                                                                                 | ** ** | ** **                                                                                 | ** ** | **Three Months Ended **                                                                        | ** ** | **Twelve Months Ended** | ** ** |
| ** **                                                                                                 | ** ** | ** **                                                                                 | ** ** | **2008**                                                                                                      | ** ** | **2007** | ** ** | **2008** | ** ** | **2007** | ** ** |
|                                                                                                       |       |                                                                                       |       |                                                                                                          |       |   |   |   |   |   |   |
| Commodity  contracts – electric segment                                                               |       | Fuel Expense                                                                               |       | $                                                                                                             | 302        |   | $ | — |   | $ | 302 |   | $ | — |   |
|                                                                                                       |       |                                                                                       |       |                                                                                                          |       |   |   |   |   |   |   |
| **Total  Electric Segment**                                                                                | ** ** | ** **                                                                                 | ** ** | **$**                                                                                                         | **302**    | ** ** | **$** | **—** | ** ** | **$** | **302** | ** ** | **$** | **—** | ** ** |

 

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(1) All of our gas hedging activities are related to stabilizing fuel costs as partof our fuel procurement program and are not speculative activities. Ifconditions change, such as a planned unit outage, we may need to re-designateand/or unwind some of our previous derivatives designated under FAS 133. Inthis instance, these derivatives would be classified into the category above.

 

Wealso enter into fixed-price forward physical contracts for the purchase ofnatural gas, coal and purchased power. These contracts are not subject to the fairvalue accounting of FAS 133 because they are considered to be normal purchases.We have instituted a process to determine if any future executed contracts thatotherwise qualify for the normal purchases exception contain a price adjustmentfeature and will account for these contracts accordingly.

 

Asof April 18, 2008, 92% of our anticipated volume of natural gas usage forour electric operations for the remainder of year 2008 is hedged, eitherthrough physical or financial contracts, at an average price of $6.758 perDekatherm (Dth). In addition, the following volumes and percentages of ouranticipated volume of natural gas usage for our electric operations for thenext five years are hedged at the following average prices per Dth:

** **
| **Year** | ** ** | **% Hedged** | ** ** | **Dth Hedged** | ** ** | **Average Price** | ** ** |
|----------|------------|-------------------|------------|---------------------|------------|------------------------|------------|
| 2009     |       | 55                | %          | 4,696,000           |       | $                      | 6.060      |   |
| 2010     |       | 34                | %          | 3,200,000           |       | $                      | 5.561      |   |
| 2011     |       | 34                | %          | 3,200,000           |       | $                      | 5.561      |   |
| 2012     |       | 13                | %          | 1,200,000           |       | $                      | 7.295      |   |
| 2013     |       | 13                | %          | 1,200,000           |       | $                      | 7.295      |   |

 

OnFebruary 15, 2008, we unwound 992,000 Dths of physical gas contractsoriginally scheduled for delivery in July and August of 2010 and2011. This transaction resulted in a gain of approximately $1.3 million aftertax which was recorded in the Statement of Operations in the first quarter of2008. We believe it is probable that we will take physical delivery under theremaining physical gas forward contracts.

 

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*Gas*

 

We attempt to mitigate our natural gas price riskfor our gas segment by a combination of (1) injecting natural gas intostorage during the off-heating season months, (2) purchasing physicalforward contracts and (3) purchasing financial derivative contracts. Wetarget to have 95% of our storage capacity full by November 1 for theupcoming winter heating season. As the winter progresses, gas is withdrawn fromstorage to serve our customers. As of April 18, 2008, we had 0.1 millionDths in storage on the three pipelines that serve our customers. Thisrepresents 6% of our storage capacity. Our long-term hedge strategy is tomitigate price volatility for our customers by hedging a minimum of 50% ofcurrent year, up to 50% of second year and up to 20% of third year expected gasusage by the beginning of the Actual Cost Adjustment (ACA)year at September 1. A PurchasedGas Adjustment (PGA) clause is included in our rates for our gas segmentoperations, therefore, we mark to market any unrealized gains or losses and anyrealized gains or losses relating to financial derivative contracts to aregulatory asset or regulatory liability account on our balance sheet.

 

Thefollowing table sets forth “mark-to-market” pre-tax gains / (losses) fromfinancial hedging instruments for the gas segment for each of the periods endedMarch 31, (in thousands). These gains and losses are recorded to aregulatory asset or liability account because we have a commission approvednatural gas cost recovery mechanism.

 
| **Derivatives Not Designated as**       | ** ** | **Balance Sheet   Classification  of Gain or** | ** ** | **Amount of Gain / (Loss) Recognized on Balance   Sheet ** | ** ** |
|--------------------------------------------------------|------------|--------------------------------------------------------------------|------------|---------------------------------------------------------------------------------------------------------|------------|
| **Hedging Instruments Under FAS ** | ** ** | **(Loss) on**                                                 | ** ** | **Three Months Ended **                                                                  | ** ** | **Twelve Months Ended** | ** ** |
| **133**                                                | ** ** | **Derivative**                                                     | ** ** | **2008**                                                                                                | ** ** | **2007** | ** ** | **2008** | ** ** | **2007** | ** ** |
|                                                   |       |                                                               |       |                                                                                                    |       |   |   |   |   |   |   |
| Commodity  contracts – gas segment                |       | Regulatory assets                                                  |       | $                                                                                                       | 1,210      |   | $ | 1,530 |   | $ | 1,210 |   | $ | 1,530 |   |
|                                                   |       |                                                               |       |                                                                                                    |       |   |   |   |   |   |   |
| **Total  Effective - Gas Segment**                     | ** ** | ** **                                                         | ** ** | **$**                                                                                                   | **1,210**  | ** ** | **$** | **1,530** | ** ** | **$** | **1,210** | ** ** | **$** | **1,530** | ** ** |

 

**Note 6– Financing**

 

On March 11, 2008, we amended theIndenture of Mortgage and Deed of Trust of The Empire District Electric Company(EDE Mortgage) in order to provide us with additional flexibility to paydividends to our shareholders by increasing the basket available to paydividends by $10.75 million. The amendment followed the successful completionof a solicitation of consents from the holders of our First Mortgage Bondsoutstanding under the EDE Mortgage. We received consents from holders of 94.46%in aggregate principal amount of the outstanding bonds and paid fees ofapproximately $1.6 million to the consenting bondholders.

 

On December 12,2007, we sold 3,000,000 shares of our common stock in an underwritten publicoffering for $23.00 per share. The sale resulted in net proceeds ofapproximately $65.7 million ($69.0 million less issuance costs of $3.3million). The proceeds were added to our general funds and used to paydown short-term indebtedness incurred, in part, as a result of our on-goingconstruction program.

 

OnJuly 15, 2005, we entered into a $150 million unsecured revolving creditfacility 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 onour current credit ratings and the pricing schedule in the line of creditfacility. On March 14, 2006, we entered into the First Amended andRestated Unsecured Credit Agreement which amends and restates the $150 millionunsecured revolving credit facility. The principal amount of the creditfacility was increased to $226 million, with the additional $76 millionallocated to support a letter of credit issued in connection with ourparticipation in the Plum Point Energy Station project. This extra $76 millionof availability reduces over a four year period in line with the amount ofconstruction expenditures we owe for Plum Point Unit 1 and was $34.0 million asof May 1, 2008. The unallocated credit facility is used for workingcapital, 

 

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generalcorporate purposes and to back-up our use of commercial paper. This facilityrequires our total indebtedness (which does not include our note payable to thesecuritization trust) to be less than 62.5% of our total capitalization at theend of each fiscal quarter and our EBITDA (defined as net income plus interest,taxes, depreciation and amortization) to be at least two times our interestcharges (which includes interest on the note payable to the securitizationtrust) 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 thecredit facility and will prohibit us from borrowing funds thereunder. As of March 31,2008, we are in compliance with these ratios. This credit facility is alsosubject to cross-default if we default on in excess of $10 million in theaggregate on our other indebtedness. This arrangement does not serve to legallyrestrict the use of our cash in the normal course of operations. There were nooutstanding borrowings under this agreement at March 31, 2008, however,$74.2 million of the availability thereunder was used at such date to back upour outstanding commercial paper.

 

**Note 7– Commitments and Contingencies**

 

Weare a party to various claims and legal proceedings arising out of the normalcourse of our business. Management regularly analyzes this information, and hasprovided accruals for any liabilities, in accordance with the guidelines ofStatement of Financial Accounting Standards SFAS 5, “Accounting forContingencies” (FAS 5). In the opinion of management, it is not probable, giventhe company’s defenses, that the ultimate outcome of these claims and lawsuitswill have a material adverse affect upon our financial condition, or results ofoperations or cash flows.

 

**Coal, Natural Gas and Transportation Contracts**

 

Wehave entered into long and short-term agreements to purchase coal and naturalgas for our energy supply and natural gas operations. Under these contracts,the natural gas supplies are divided into firm physical commitments andderivatives that are used to hedge future purchases. The firm physical gas andtransportation commitments total $41.3 million for April 1, 2008 through March 31,2009, $45.7 million for April 1, 2009 through March 31, 2011, $44.0million for April 1, 2011 through March 31, 2013 and $66.9 millionfor April 1, 2013 and beyond. In the event that this gas cannot be used atour plants, the gas would remain in storage or be liquidated at market price.

 

Wehave coal supply agreements and transportation contracts in place to providefor the delivery of coal to the plants. These contracts are written with ForceMajeure clauses that enable us to reduce tonnages or cease shipments undercertain circumstances or events. These include mechanical or electricalmaintenance items, acts of God, war or insurrection, strikes, weather and otherdisrupting events. This reduces the risk we have for not taking the minimumrequirements of fuel under the contracts. Due to the extended Asbury maintenance outage from December 9, 2007through February 10, 2008, we issued force majeure notices to our Westerncoal suppliers and to the railroads suspending Western coal shipments duringthe outage. This relieved us of our contractual obligations to receiveshipments of coal to the extent caused by the Asbury outage. The minimumrequirements are $27.2 million for April 1, 2008 through March 31,2009, and $25.9 million for April 1, 2009 through March 31, 2011.

 

**Purchased Power**

 

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

 

Wehave contracted with Westar Energy for the purchase of capacity and energythrough May 31, 2010. Commitments under this contract total approximately$21.7 million through May 31, 2010.

 

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Wealso have a long term (30 year) agreement for the purchase of capacity from thePlum Point Energy Station, a new 665-megawatt, coal-fired generating facilitywhich is being built near Osceola, Arkansas. Construction began in the springof 2006 with completion scheduled for 2010. We have the option to convert the50 megawatts covered by the purchased power agreement into an ownershipinterest in 2015. Commitments under this contract total approximately $47.5million through June 30, 2015.

 

Wehave entered into a 20-year purchased power agreement with Cloud CountyWindfarm, LLC, owned by Horizon Wind Energy, Houston, Texas to purchase theenergy generated at the approximately 105-megawatt Phase 1 Meridian Way WindFarm to be located in Cloud County, Kansas and a 20-year contract with ElkRiver Windfarm, LLC, owned by IBERDROLA RENEWABLES, Inc. (formerly known as PPMEnergy), to purchase the energy generated at the 150-megawatt Elk RiverWindfarm located in Butler County, Kansas. Although these agreements areconsidered operating leases under GAAP, payments for these wind agreements arerecorded as purchased power expenses, and, because of the contingent nature ofthese payments, are not included in the operating lease obligations discussedbelow.

 

**New Construction**

 

OnMarch 14, 2006, we entered into contracts to purchase an undividedinterest in 50 megawatts of the Plum Point Energy Station’s new 665-megawatt,coal-fired generating facility which is being built near Osceola, Arkansas. Theestimated cost is approximately $86.5 million, excluding AFUDC. 

 

OnJune 13, 2006, we announced we had entered into an agreement with KansasCity Power & Light (KCP&L) to purchase an undivided ownershipinterest in the coal-fired Iatan 2 generating facility. We will own 12%, orapproximately 100 megawatts, of the 850-megawatt unit. Construction began inthe spring of 2006 with completion scheduled for 2010. On May 7, 2008,KCP&L announced an update of their estimated construction figures for theconstruction of the Iatan 2 plant and for the environmental upgrades at theIatan 1 plant. Our share of the Iatan 2 construction costs will increase from arange of approximately $183.6 million to $200.5 million to a range ofapproximately $218 million to $230 million. All of these estimated construction expenditures exclude AFUDC. The updatedestimate of our share of the cost for environmental upgrades at the Iatan 1plant is a range of approximately $56 million to $60 million, representing anincrease of 22%-30% compared to the previous estimate of approximately $46million. The in-service date for the Iatan No. 1 project is expected to beFebruary 2009.

 

Anew combustion turbine previously scheduled to be installed by the summer of2011 will be delayed for at least one year as our generation regulation needs forour purchased power agreements are being met through a combination of ourexisting units and the SPP energy imbalance market.

 

**Leases**

 

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

 

OnDecember 10, 2004, we entered into a 20-year contract with Elk RiverWindfarm, LLC to purchase the energy generated at the 150-megawatt Elk RiverWindfarm located in Butler County, Kansas. We have contracted to purchaseapproximately 550,000 megawatt-hours of energy per year, or approximately 10%of our annual needs, under the contract, which was declared 

 

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commercialon December 15, 2005. We do not own any portion of the windfarm. Paymentsfor wind energy from the Elk River Windfarm are contingent upon output of thefacility. Annual payments can run from zero to a maximum of approximately $16.9million based on a 20-year average cost.

 

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

 

We also currently have short-term operating leasesfor two unit trains to meet coal delivery demands and garage and officefacilities for our electric segment and six service center properties for ourgas segment. In addition we have a five-year capital lease for telephoneequipment.

 

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

 
| **Capital Leases**                          |
|--------------------------------------------------|
| ** **                                       | ** ** |
| 2008                                             |   | 288 |   |
| 2009                                             |   | 288 |   |
| 2010                                             |   | 171 |   |
| 2011                                             |   | 2 |   |
| Thereafter                                       |   | — |   |
| **Total  minimum payments**                      | ** ** | **$** | **749** | ** ** |
| Less amount  representing maintenance            |   | 249 |   |
| **Net  minimum lease payments**                  | ** ** | **500** | ** ** |
| Less amount  representing interest               |   | 40 |   |
| **Present  value of net minimum lease payments** | ** ** | **$** | **460** | ** ** |

 
| **Operating Leases**   |
|-----------------------------|
| ** **                  | ** ** |
| 2008                        |   | $ | 1,505 |   |
| 2009                        |   | 539 |   |
| 2010                        |   | 353 |   |
| 2011                        |   | 285 |   |
| 2012                        |   | 205 |   |
| Thereafter                  |   | 633 |   |
| **Total  minimum payments** | ** ** | **$** | **3,520** | ** ** |

 

The gross amount of assets recorded under capitalleases totaled $1.3 million at March 31, 2008. The accumulated amount ofamortization for our capital leases was $0.3 million at March 31, 2008.

 

**Environmental Matters**

 

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

 

**ElectricSegment**

 

*Air.* The 1990 Amendments to the Clean Air Act, referredto as the 1990 Amendments, affect the Asbury, Riverton, State Line and IatanPower Plants and Units 3 and 4 (the FT8 peaking units) at the Empire EnergyCenter. The 1990 Amendments require affected plants to meet certain emissionstandards, including maximum emission levels for sulfur dioxide (SO2) andnitrogen oxides (NOx).

 

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SO2Emissions.  Under the1990 Amendments, the amount of SO2 an affected unit can emit is regulated. Eachexisting affected unit has been allocated a specific number of emissionallowances, each of which allows the holder to emit one ton of SO2. Utilitiescovered by the 1990 Amendments must have emission allowances equal to thenumber of tons of SO2 emitted during a given year by each of their affectedunits. The annual reconciliation of allowances, which occurs on a facility widebasis, is held each March 1 for the previous calendar year. Allowances maybe traded between plants or utilities or “banked” for future use. A market forthe trading of emission allowances exists on the Chicago Board of Trade. TheEnvironmental Protection Agency (EPA) withholds annually a percentage of theemission allowances allocated to each affected unit and sells those emissionallowances through a direct auction. We receive compensation from the EPA forthe sale of these withheld allowances.

 

OurAsbury, Riverton (other than the gas-fired combustion turbines) and IatanPlants burn a blend of low sulfur Western coal (Powder River Basin) and highersulfur blend coal and petroleum coke, or burn 100% low sulfur Western coal. Inaddition, tire-derived fuel (TDF) is used as a supplemental fuel at the AsburyPlant. The Riverton Plant can also burn natural gas as its primary fuel. TheState Line Plant, the Energy Center Units 3 and 4 and Riverton Unit 12 aregas-fired facilities and do not receive SO2 allowances. In the near term,annual allowance requirements for the State Line Plant, the Energy Center Units3 and 4 and Riverton Unit 12, which are not expected to exceed 20 allowancesper year, will be transferred from our inventoried bank of allowances. In 2007,the combined actual SO2 allowance need for all affected plant facilitiesexceeded the number of allowances allocated to us by the EPA. Based on our March 1,2008 EPA reconciliation, 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 2008emissions will again exceed the number of allowances allocated by the EPA.Based on current SO2 allowance usage projections, we expect to exhaust ourbanked allowances by the end of 2010.

 

Onceour SO2 allowance bank is exhausted, we will need to purchase additional SO2 allowancesor build a Flue Gas Desulphurization (FGD) scrubber system at our Asbury Plant.Based on current and projected SO2 allowance prices and high-level estimatedFGD scrubber construction costs ($81 million in 2010 dollars), we expect itwill be more economical for us to purchase SO2 allowances than to build ascrubber at the Asbury Plant. We would expect the costs of SO2 allowances to befully recoverable in our rates. In addition, projected engineering andconstruction timeframes for a new scrubber make it unfeasible at this time toconstruct a scrubber by the end of 2010.

 

OnJuly 14, 2004, we filed an application with the MPSC seeking an orderauthorizing us to implement a plan for the management, sale, exchange, transferor 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 tomanage our SO2 allowance inventory in accordance with our SO2 AllowanceManagement Policy (SAMP). The SAMP allows us to swap banked allowances forfuture vintage allowances and/or monetary value and, in extreme marketconditions, to sell SO2 allowances outright for monetary value. The Stipulationand Agreement became effective March 11, 2005, although we have not yetswapped or sold any allowances. Our banked allowances are not assigned a costvalue. The allowances are removed from inventory on a FIFO basis.

 

SO2emissions will be further regulated as described in the Clean Air Interstate Rule sectionbelow.

 

NOxEmissions. The Asbury, Iatan, State Line, Energy Center andRiverton Plants are each in compliance with the NOx limits applicable to themunder the 1990 Amendments as currently operated.

 

TheAsbury 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 265,100discarded passenger car tires.

 

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Underthe MDNR’s Missouri NOx Rule, our Iatan, Asbury, State Line and Energy Centerfacilities, like other facilities in Western Missouri, are generally subject toa maximum NOx emission rate of 0.35 lbs/MMBtu during the ozone season of May 1through September 30. However, facilities which burn at least 100,000passenger tire equivalents of TDF per year, including our Asbury Plant, aresubject to a higher NOx emission limit of 0.68 lbs/MMBtu. All of our plantscurrently meet the required emission limits and additional NOx controls are notrequired.

 

In March 2008, the EPAlowered the National Ambient Air Quality Standard (NAAQS) for ozone from 84 ppbto 75 ppb. Ozone, also called ground level smog, is formed by the mixing of NOxand Volatile Organic Compounds (VOCs) in the presence of sunlight. It ispossible that most of southwest Missouri will be classified as non-attainmentor non-classified by the EPA in 2010 or later. We anticipate that the EPA willclassify the Kansas City area, where Iatan 1 is located, as non-attainment in2010. At this time we do not foresee the need for additional controls exceedingthose already required by CAIR. In addition, our units do not emit appreciableVOCs. We do not anticipate that southeast Kansas will be classified asnon-attainment under the new ozone NAAQS.

 

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

 

Clean Air Interstate Rule (CAIR)

 

TheEPA issued its final CAIR on March 10, 2005. CAIR governs NOx and SO2emissions from fossil fueled units greater than 25 megawatts and will affect 28states, including Missouri, where our Asbury, Energy Center, State Line andIatan Plants are located and Arkansas where the Plum Point Energy Station isbeing constructed. Kansas is not included in CAIR and our Riverton Plant willnot be affected.

 

The CAIR is not directed to specific generationunits, but instead, requires the states (including Missouri and Arkansas) todevelop State Implementation Plans (SIPs) to comply with specific NOx and SO2state-wide annual budgets. Missouri and Arkansas have finalized theirrespective regulations and submitted their SIPs to the EPA for approval. TheArkansas SIP, which addresses ozone season NOx only, was approved and becameeffective on November 26, 2007 and the Missouri SIP, which addressesannual and ozone season NOx and SO2, was approved and became effective on December 14,2007. We will receive our full allotment of allowances as published in theMissouri CAIR Rule. Under the Arkansas CAIR rule, we will not receiveallowances until approximately six years after Plum Point Unit 1 isoperational. In the interim we will transfer allowances from our Missouriunits. Based on the SIPs for Missouri and Arkansas, it appears we will haveexcess annual and ozone season NOx allowances. SO2 allowances must be utilizedat a 2:1 ratio for our Missouri units as compared to our non-CAIR Kansas unitsbeginning in 2010. Based on current SO2 allowance usage projections, we expectto exhaust our banked allowances by the end of 2010 and will need to purchaseadditional SO2 allowances or build a scrubber at our Asbury Plant.

 

Inorder to help meet anticipated CAIR requirements and to meet air permitrequirements for Iatan Unit 2, pollution control equipment is being installedon Iatan Unit 1 with the in-service date expected to be February 2009. Thisequipment includes a Selective Catalytic Reduction (SCR) system, an FGDscrubber and a baghouse, with our share of the capital cost estimated to bebetween $56 million and $60 million, excluding AFUDC. Of this amount,approximately $3.9 million was incurred in 2006 and $12.1 million in 2007with estimated expenditures of approximately $25.7 million in 2008 and $17.5million in 2009. This project was also included as part of our ExperimentalRegulatory Plan approved by the MPSC.

 

Alsoto help meet anticipated CAIR requirements, we constructed an SCR at Asburythat was completed in November 2007 and placed in service in February 2008at a total cost of approximately $31.0 million (excluding AFUDC), of which $28.1million was expended through December 31, 2007 with the remainder expendedin 2008. This project was also included as part of our Experimental RegulatoryPlan approved by the MPSC.

 

Additionalpollution control equipment to comply with CAIR may become economicallyjustified at the Asbury Plant sometime prior to 2015 and may include an FGDscrubber to control SO2 and a baghouse at an estimated capital cost of $100million.

 

CleanAir Mercury Rule (CAMR)

 

OnMarch 15, 2005, the EPA issued the CAMR regulations for mercury emissionsby power plants under the requirements of the 1990 Amendments to the Clean AirAct. The new mercury emission limits for Phase 1 were scheduled to go intoeffect January 1, 2010 and remain in effect until January 1, 2018.Beginning January 1, 2018, more restrictive mercury emission limits werescheduled to go into effect for Phase 2 of CAMR. These regulations werechallenged in the U.S. Court of Appeals for the District of Columbia Circuit bya group of states led by New Jersey. On 

 

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February 8,2008, the Court of Appeals issued its opinion and vacated the EPA’s CAMRregulations. The EPA is required to reconsider the regulation of mercury under Section 112of the CAA. At this point it is too early to determine the effects of thisruling.

 

TheCAMR was not directed to specific generation units, but instead, required thestates (including Missouri, Kansas and Arkansas) to develop SIPs to comply withspecific mercury state-wide annual budgets. Missouri, Kansas and Arkansas havefinalized their respective regulations and submitted their SIPs to the EPA. Theproposed SIPs for all states include allowance trading programs for mercurythat could allow compliance without additional capital expenditures. The EPAhas not yet issued guidance to the states regarding the vacated regulation andrecommended future actions.

 

Basedon CAMR, we installed a mercury analyzer at Asbury during late 2007 andscheduled the installation of two mercury analyzers at Riverton during 2008 inorder 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. We will complete the installation of the mercury analyzers at Riverton inanticipation of future mercury regulations.

 

CO2 Emissions

 

Our coal and gas plants emit carbon dioxide (CO2), agreenhouse gas. Although not currently regulated, increasing public concern andpolitical pressure from local, regional, national and international bodies mayresult in the passage of new laws mandating limits on greenhouse gas emissionssuch as CO2. Several bills addressing climate change have been introduced inthe U.S. Congress and, in April 2007, the U.S. Supreme Court issued adecision ruling the EPA improperly declined to address CO2 impacts in arule-making related to new motor vehicle emissions. While this decision is notdirectly applicable to power plant emissions, the reasoning of the decisioncould affect other regulatory programs. Various proposals in the U.S. Congresscould require us to purchase offsets or allowances for some or all of our CO2emissions, or otherwise affect us based on the amount of CO2 we generate. Theimpact on us of any future greenhouse gas regulation will depend in large parton the details of the requirements and the timetable for mandatory compliance.

 

*Water.* We operate under the Kansas and Missouri WaterPollution Plans that were implemented in response to the Federal WaterPollution Control Act Amendments of 1972. The Asbury, Iatan, Riverton, EnergyCenter and State Line plants are in compliance with applicable regulations andhave received discharge permits and subsequent renewals as required. The StateLine permit was renewed in May 2007. The Energy Center permit was renewedin September 2005 and the Asbury Plant permit was renewed in December 2005.

 

TheRiverton Plant is affected by final regulations for Cooling Water IntakeStructures issued under the Clean Water Act (CWA) Section 316(b) PhaseII. The regulations became final on February 16, 2004 and required thesubmission of a Sampling Report and Comprehensive Demonstration Study with thepermit renewal in 2008. A Proposal for Information Collection (PIC) wasapproved by the Kansas Department of Health and Environment (KDHE). Aquaticsampling commenced in April 2006 in accordance with the PIC and wascompleted in August 2007. Analysis of the sampling and summary reports wascompleted during the first quarter of 2008 and submitted to the KDHE. Thesereports indicate that the effect of the cooling water intake structure onEmpire Lake’s aquatic life is insignificant. The need for a furtherDemonstration Study is not expected. On January 25, 2007, the UnitedStates Court of Appeals for the Second Circuit remanded key sections of the EPA’sFebruary 16, 2004 regulations. On July 9,2007, the EPA suspended the regulation and is expected to revise and re-proposethe regulation by December 2008. We will monitor the EPA revision processand comment appropriately. In addition, on April 14, 2008 certiorari wasgranted by the United States Supreme Court limited to the review as to whether Section 316(b) ofthe CWA authorized the EPA to compare costs with benefits in determining thebest technology available for minimizing adverse environmental impacts atcooling water intake structures. The permit renewal application will beprepared and submitted as scheduled following KDHE guidance. Under the initial316(b) regulations, we did not expect costs associated with compliance tobe

 

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material. We will reassess costs after the SupremeCourt issues its ruling and the revised rules are complete.

 

*Other.*Under Title V of the 1990 Amendments, we must obtainsite operating permits for each of our plants from the authorities in the statein 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. Wehave been issued permits for Asbury, Iatan, Riverton, State Line and the EnergyCenter Plants. We submitted the required renewal applications for the StateLine and Energy Center Title V permits in 2003 and the Asbury Title V permit in2004 and will operate under the existing permits until the MDNR issues therenewed permits. A Compliance Assurance Monitoring (CAM) plan is required bythe renewed permit for Asbury. We estimate that the capital costs associatedwith the CAM plan will not exceed $2 million.

 

Anew air permit was issued for the Iatan Generating Station on January 31,2006. The new permit covers the entire Iatan Generating Station and includesthe existing Unit No. 1 and Iatan Unit No. 2 currently underconstruction. The new permit limits Unit No. 1 to a maximum of 6,600 MMBtuper hour of heat input. The 6,600 MMBtu per hour heat input limit is in effectuntil the new SCR, scrubber, and baghouse are completed, currently estimated tobe late in the fourth quarter of 2008.

 

**GasSegment**

 

The acquisition of Missouri Gas involved theproperty transfer of two former manufactured gas plant (MGP) sites previouslyowned by Aquila, Inc. and its predecessors. Site #1 is listed in the MDNRRegistry of Confirmed Abandoned or Uncontrolled Hazardous Waste Disposal Sitesin 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 toexpand our existing service center at Site #1 in Chillicothe, Missouri. Thisproject, which was completed in October 2007, included the removal of allexcavated soil and the addition of a new concrete surface replacing theexisting gravel at a cost of approximately $0.1 million. We estimate furtherremediation costs at these two sites to be no more than approximately $0.2million, based on our best estimate at this time. This estimated liability isrecorded under noncurrent liabilities and deferred credits. In our agreementwith the MPSC approving the acquisition of Missouri Gas, it was agreed that wecould 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 costsrelated to the clean up of these MGP sites would be allowed for future raterecovery. Accordingly, we concluded that rate recovery was probable and at theacquisition date, a regulatory asset of $260,000 was recorded as part of thepurchase price allocation based on our agreement with the MPSC, and inaccordance with Statement of Financial Accounting Standards No. 71 – “Accountingfor the Effects of Certain Types of Regulation” (FAS 71).

 

**Note 8 – Retirement Benefits**

 

Net periodic benefit pension cost, some of which is capitalized as acomponent of labor cost and some of which is deferred as a regulatory asset, iscomprised of the following components (in thousands):

 
| ** **                              | ** ** | **Three months ended March 31,** | ** ** |
|-----------------------------------------|------------|---------------------------------------|------------|
| ** **                              | ** ** | **Pension Benefits**                  | ** ** | **SERP** | ** ** | **Other Postretirement Benefits** | ** ** |
| ** **                              | ** ** | **2008**                              | ** ** | **2007** | ** ** | **2008** | ** ** | **2007** | ** ** | **2008** | ** ** | **2007** | ** ** |
| Service cost                            |       | $                                     | 863        |   | $ | 862 |   | $ | 12 |   | $ | 13 |   | $ | 407 |   | $ | 525 |   |
| Interest cost                           |       | 2,245                                 |       | 2,015 |   | 32 |   | 29 |   | 910 |   | 975 |   |
| Expected return  on plan assets         |       | (2,680                                | )          | (2,588 | ) |   |   |   |   | (938 | ) | (825 | ) |
| Amortization of  prior service cost (1) |       | 186                                   |       | 91 |   | (2 | ) | (3 | ) | (253 | ) | (125 | ) |
| Amortization of  net actuarial loss (1) |       | 404                                   |       | 687 |   | 30 |   | 37 |   | 140 |   | 300 |   |
| **Net  periodic benefit cost**          | ** ** | **$**                                 | **1,018**  | ** ** | **$** | **1,067** | ** ** | **$** | **72** | ** ** | **$** | **76** | ** ** | **$** | **266** | ** ** | **$** | **850** | ** ** |

 

22

----

 
| ** **                              | ** ** | **Twelve months ended March 31,** | ** ** |
|-----------------------------------------|------------|-------------------------------------------------------|------------|
| ** **                              | ** ** | **Pension Benefits**                             | ** ** | **SERP** | ** ** | **Other Postretirement Benefits** | ** ** |
| ** **                              | ** ** | **2008**                                              | ** ** | **2007** | ** ** | **2008** | ** ** | **2007** | ** ** | **2008** | ** ** | **2007** | ** ** |
| Service cost                            |       | $                                                     | 3,493      |   | $ | 3,353 |   | $ | 50 |   | $ | 49 |   | $ | 1,586 |   | $ | 1,891 |   |
| Interest cost                           |       | 8,468                                                 |       | 7,760 |   | 119 |   | 108 |   | 3,352 |   | 3,576 |   |
| Expected return  on plan assets         |       | (10,392                                               | )          | (9,900 | ) |   |   |   |   | (3,511 | ) | (2,932 | ) |
| Amortization of  prior service cost (1) |       | 683                                                   |       | 438 |   | (10 | ) | (3 | ) | (1,138 | ) | (487 | ) |
| Amortization of  net actuarial loss (1) |       | 2,318                                                 |       | 3,072 |   | 140 |   | 146 |   | 991 |   | 2,098 |   |
| **Net  periodic benefit cost**          | ** ** | **$**                                                 | **4,570**  | ** ** | **$** | **4,723** | ** ** | **$** | **299** | ** ** | **$** | **300** | ** ** | **$** | **1,280** | ** ** | **$** | **4,146** | ** ** |

 

----

(1) 2007 and 2008amounts are amortized from our regulatory asset recorded upon adoption of FAS158.

 

Basedon the performance of our pension plan assets through January 1, 2007 and2008, we were not required under the Employee Retirement Income Security Act of1974 (ERISA) to fund any additional minimum ERISA amounts with respect to 2007or 2008.

 

Weexpect to make other postretirement benefit contributions of $1.1 million in2008, of which $0.5 million has been made as of March 31, 2008.

 

**Note 9 –Stock-Based Awards and Programs**

 

Werecognized the following amounts in compensation expense and tax benefits forall of our stock-based awards and programs for the applicable periods ended March 31:

 
| ** **              | ** ** | **Three Months Ended** | ** ** | **Twelve Months Ended** | ** ** |
|-------------------------|------------|----------------------------------|------------|-----------------------------------|------------|
| **(in thousands)** | ** ** | **2008**                         | ** ** | **2007**                          | ** ** | **2008** | ** ** | **2007** | ** ** |
| ** **              |       |                             |       |                              |       |   |   |   |   |
| **Compensation**        |       | $                                | 875        |                              | $          | 753 |   | $ | 2,243 |   | $ | 1,850 |   |
| **Tax  Benefit**        |       | 324                              |       | 278                               |       | 818 |   | 669 |   |
|                         |            |                                  |            |                                   |            |  |  |  |  |  |  |  |  |

 

Activityfor our various stock plans for the three months ended March 31, 2008, issummarized below:

 

**Performance-Based Restricted Stock Awards**

 

The fair value of theestimated shares to be awarded under the 2008 grant of restricted stock wasestimated on the date of grant using a Monte Carlo option valuation model. The2007 grant was estimated on the date of grant using a lattice-based optionvaluation model. The assumptions used in each model are noted in the followingtable:

 
| ** **                               | ** ** | **2008**  | ** ** | **2007**       | ** ** |
|------------------------------------------|------------|-----------|------------|----------------|------------|
| Risk-free  interest rate                 |       | 2.44%     |       | 5.09% to 4.88% |       |
| Expected  volatility of Empire stock     |       | 19.9%     |       | 16.6%          |       |
| Expected  volatility of peer group stock |       | 20.3%     |       | 18.9%          |       |
| Expected  dividend yield on Empire stock |       | 5.4%      |       | 5.55%          |       |
| Expected  forfeiture rates               |       | 3%        |       | 3%             |       |
| Plan cycle                               |       | 3 years   |       | 3 years        |       |
| EDE percentile  performance              |       | 24th      |       | 25th           |       |
| Fair value  percentage                   |       | 113.0%    |       | 107.73%        |       |
| Grant date                               |       | 1/30/2008 |       | 1/31/2007      |       |
| Grant date fair  value per share         |       | $24.78    |       | $25.65         |       |

 

Non-vested restricted stockawards (based on target number) as of March 31, 2008 and 2007 and changesduring the three months ended March 31, 2008 and 2007 were as follows:

 

23

----

 
| ** **                        | ** ** | **YTD 2008**          | ** ** | **YTD 2007**                                     | ** ** |
|-----------------------------------|------------|----------------------------|------------|-------------------------------------------------------|------------|
| ** **                        | ** ** | **Number of  shares** | ** ** | **Weighted Average  Grant Date Price** | ** ** | **Number  of shares** | ** ** | **Weighted Average  Grant Date Price** | ** ** |
|                              |       |                       |       |                                                  |       |   |   |   |   |
| **Nonvested  at January 1,** |       | 43,400                     |       | $                                                     | 23.02      |   | 38,800 |   | $ | 22.25 |   |
| **Granted**                       |       | 21,000                     |       | $                                                     | 21.92      |   | 17,700 |   | $ | 23.81 |   |
| **Awarded**                       |       | (6,486                     | )          | $                                                     | 22.77      |   | (7,598 | ) | $ | 21.79 |   |
| **Not  Awarded**                  |       | (5,614                     | )          |                                                  |       | (5,502 | ) |   |   |
|                              |       |                       |       |                                                  |       |   |   |   |   |
| **Nonvested  at March 31,**  |       | 52,300                     |       | $                                                     | 22.64      |   | 43,400 |   | $ | 23.02 |   |

 

At March 31, 2008,there was $0.8 million of total unrecognized compensation cost related toestimated outstanding awards. This cost will be recognized over the remainingvesting period.

 

**StockOptions**

 

Asummary of option activity under the plan during the three months ended March 31,2008 and 2007 is presented below:

 
| ** **                      | ** ** | **2008**    | ** ** | **2007**                               | ** ** |
|---------------------------------|------------|-------------|------------|----------------------------------------|------------|
| ** **                      | ** ** | **Options** | ** ** | **Weighted  Average  Exercise  Price** | ** ** | **Options** | ** ** | **Weighted  Average  Exercise  Price** | ** ** |
| Outstanding at  January 1, |       | 149,200     |       | $                                      | 23.04      |   | 135,000 |   | $ | 22.21 |   |
| Granted                         |       | 56,400      |       | $                                      | 21.92      |   | 64,200 |   | $ | 23.83 |   |
| Exercised                       |       | —      |       | —                                 |       | 50,000 |   | $ | 21.79 |   |
| Outstanding at  March 31,  |       | 205,600     |       | $                                      | 22.73      |   | 149,200 |   | $ | 23.04 |   |
| Exercisable at  March 31,  |       | 43,300      |       | $                                      | 22.67      |   | 4,200 |   | $ | 21.79 |   |

 

Theaggregate intrinsic value at March 31, 2008 was $0. The aggregateintrinsic value at March 31, 2007 was $0.2 million. The intrinsic value ofthe unexercised options is the difference between Empire’s closing stock priceon the last day of the quarter and the exercise price multiplied by the numberof in the money options had all option holders exercised their option on thelast day of the quarter. The intrinsic value is zero if such closing price isless than the exercise price.

 

Therange of exercise prices for the options outstanding at March 31, 2008 was$21.79 to $23.81. The weighted-average remaining contractual life ofoutstanding options at March 31, 2008 and 2007 was 7.8 years and 8.3years, respectively. As of March 31, 2008, there was $0.5 million of totalunrecognized compensation expense related to the non-vested options grantedunder the plan. That cost will be recognized over a period of 1 to 3 years.

 
| ** **                                 | ** ** | **Stock Options** | ** ** |
|--------------------------------------------|------------|------------------------|------------|
| ** **                                 | ** ** | **2008**               | ** ** | **2007** | ** ** |
| **Weighted  average fair value of grants** |       | $2.42                  |       | $2.38 |   |
| **Risk-free  interest rate**               |       | 3.38%                  |       | 4.68% |   |
| **Dividend  yield**                        |       | 5.40%                  |       | 5.33% |   |
| **Expected  volatility**                   |       | 20.0%                  |       | 16.13% |   |
| **Expected  life in months**               |       | 78                     |       | 60 |   |
| **Grant  Date**                            |       | 1/30/08                |       | 1/31/07 |   |

 

24

----

 

**Note 10- Regulated - Other Operating Expense**

 

Thefollowing table sets forth the major components comprising “Regulated – other”under “Operating Revenue Deductions” on our consolidated statements ofoperations (in thousands) for all periods presented ended March 31:

 
| ** **                                         | ** ** | **Three Months  Ended** | ** ** | **Three Months  Ended** | ** ** | **Twelve Months  Ended** | ** ** | **Twelve Months  Ended** | ** ** |
|----------------------------------------------------|------------|------------------------------|------------|------------------------------|------------|-------------------------------|------------|-------------------------------|------------|
| ** **                                         | ** ** | **2008**                     | ** ** | **2007**                     | ** ** | **2008**                      | ** ** | **2007**                      | ** ** |
| Electric  transmission and distribution expense    |       | $                            | 2,657      |                         | $          | 2,064                         |       | $                             | 10,059     |   | $ | 8,469 |   |
| Natural gas  transmission and distribution expense |       | 474                          |       | 443                          |       | 1,786                         |       | 1,485                         |       |
| Power operation  expense (other than fuel)         |       | 2,713                        |       | 2,359                        |       | 10,770                        |       | 9,795                         |       |
| Customer  accounts and assistance expense          |       | 2,548                        |       | 2,118                        |       | 9,628                         |       | 8,639                         |       |
| Employee pension  expense (1)                      |       | 1,554                        |       | 1,816                        |       | 6,290                         |       | 5,164                         |       |
| Employee  healthcare plan (1)                      |       | 1,943                        |       | 1,777                        |       | 8,065                         |       | 7,584                         |       |
| General office  supplies and expense               |       | 2,442                        |       | 2,566                        |       | 10,170                        |       | 8,763                         |       |
| Administrative  and general expense                |       | 2,958                        |       | 2,820                        |       | 11,002                        |       | 11,411                        |       |
| Allowance for  uncollectible accounts              |       | 572                          |       | 1,354                        |       | 3,890                         |       | 3,115                         |       |
| Miscellaneous  expense                             |       | 37                           |       | 45                           |       | 242                           |       | 159                           |       |
| Total                                              |       | $                            | 17,898     |                         | $          | 17,362                        |       | $                             | 71,902     |   | $ | 64,584 |   |

 

----

(1) Includes effectsof regulatory treatment for pension and other postretirement benefits but doesnot include capitalized portion or amount deferred to a regulatory asset.

 

**Note 11–Segment Information**

 

We operate our business asthree segments:  electric, gas and other.As part of our electric segment, we also provide water service to three townsin Missouri. EDG is our wholly owned subsidiary formed to hold the Missouri Gasassets acquired from Aquila, Inc. on June 1, 2006. The other segmentconsists primarily of a subsidiary for our fiber optics business.

 

In August 2006, we soldour controlling 52% interest in MAPP, a company that specialized inclose-tolerance custom manufacturing for the aerospace, electronics, telecommunicationsand machinery industries*.* In December 2006,we sold our 100% interest in Conversant, Inc., a software company thatmarketed Customer Watch, an Internet-based customer information systemsoftware. 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 othersegment, have been classified as discontinued operations and are not includedin our segment information.

 

Thetables below present statement of income information, balance sheet informationand capital expenditures of our business segments.

 
| ** **                           | ** ** | **For the quarter ended March 31,  2008** | ** ** |
|--------------------------------------|------------|--------------------------------------------------------------------|------------|
| **($-000’s)**                   | ** ** | **Electric**                                                       | ** ** | **Gas** | ** ** | **Other** | ** ** | **Eliminations** | ** ** | **Total** | ** ** |
| **Statement  of Income Information** |       |                                                               |       |   |   |   |   |   |   |   |   |
| Revenues                             |       | $                                                                  | 108,740    |   | $ | 27,275 |   | $ | 1,061 |   | $ | (130 | ) | $ | 136,946 |   |
| Depreciation and  amortization       |       | 12,819                                                             |       | 480 |   | 322 |   | — |   | 13,621 |   |
| Federal and  state income taxes      |       | 1,488                                                              |       | 1,509 |   | 108 |   | — |   | 3,105 |   |
| Operating income                     |       | 10,945                                                             |       | 3,379 |   | 235 |   | — |   | 14,559 |   |
| Interest income                      |       | 103                                                                |       | 115 |   | — |   | (139 | ) | 79 |   |
| Interest expense                     |       | 8,979                                                              |       | 989 |   | 60 |   | (139 | ) | 9,889 |   |
| Income from  AFUDC (debt and equity) |       | 2,465                                                              |       | — |   | — |   | — |   | 2,465 |   |
| Income from  continuing operations   |       | 4,359                                                              |       | 2,455 |   | 176 |   | — |   | 6,990 |   |
|                                 |       |                                                               |       |   |   |   |   |   |   |   |   |
| **Capital  Expenditures**            |       | $                                                                  | 54,248     |   | $ | 436 |   | $ | 415 |   |   |   | $ | 55,099 |   |
|                                      |            |                                                                    |            |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

25

----

 
| ** **                           | ** ** | **For the quarter ended March 31,  2007** | ** ** |
|--------------------------------------|------------|------------------------------------------------|------------|
| **($-000’s)**                   | ** ** | **Electric**                                   | ** ** | **Gas** | ** ** | **Other** | ** ** | **Eliminations** | ** ** | **Total** | ** ** |
| **Statement  of Income Information** |       |                                           |       |   |   |   |   |   |   |   |   |
| Revenues                             |       | $                                              | 97,361     |   | $ | 27,590 |   | $ | 795 |   | $ | (96 | ) | $ | 125,650 |   |
| Depreciation and  amortization       |       | 11,996                                         |       | 466 |   | 236 |   | — |   | 12,698 |   |
| Federal and  state income taxes      |       | 572                                            |       | 1,051 |   | 15 |   | — |   | 1,638 |   |
| Operating income                     |       | 9,118                                          |       | 2,605 |   | 190 |   | — |   | 11,913 |   |
| Interest income                      |       | 266                                            |       | 37 |   | — |   | (209 | ) | 94 |   |
| Interest expense                     |       | 8,359                                          |       | 987 |   | 165 |   | (209 | ) | 9,302 |   |
| Income from  AFUDC (debt and equity) |       | 2,047                                          |       | 14 |   | — |   | — |   | 2,061 |   |
| Income from  continuing operations   |       | 2,843                                          |       | 1,663 |   | 25 |   |   |   | 4,531 |   |
|                                 |       |                                           |       |   |   |   |   |   |   |   |   |
| **Capital  Expenditures (1)**        |       | $                                              | 47,949     |   | $ | 222 |   | $ | 694 |   |   |   | $ | 48,865 |   |
|                                      |            |                                                |            |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

----

(1) Does not include the acquisition of the Missouri gas operations.

 
| ** **                           | ** ** | **For the twelve months ended March 31,  2008** | ** ** |
|--------------------------------------|------------|-------------------------------------------------------------------------------|------------|
| **($-000’s)**                   | ** ** | **Electric**                                                                  | ** ** | **Gas** | ** ** | **Other** | ** ** | **Eliminations** | ** ** | **Total** | ** ** |
| **Statement  of Income Information** |       |                                                                          |       |   |   |   |   |   |   |   |   |
| Revenues                             |       | $                                                                             | 438,419    |   | $ | 59,563 |   | $ | 3,946 |   | $ | (472 | ) | $ | 501,456 |   |
| Depreciation and  amortization       |       | 50,461                                                                        |       | 1,903 |   | 1,159 |   | — |   | 53,523 |   |
| Federal and  state income taxes      |       | 14,506                                                                        |       | 1,030 |   | 374 |   | — |   | 15,910 |   |
| Operating income                     |       | 62,049                                                                        |       | 5,462 |   | 701 |   | — |   | 68,212 |   |
| Interest income                      |       | 399                                                                           |       | 452 |   | — |   | (539 | ) | 312 |   |
| Interest expense                     |       | 36,402                                                                        |       | 3,959 |   | 146 |   | (539 | ) | 39,968 |   |
| Income from  AFUDC (debt and equity) |       | 8,066                                                                         |       | 5 |   | — |   | — |   | 8,071 |   |
| Income from continuing  operations   |       | 33,351                                                                        |       | 1,761 |   | 527 |   | — |   | 35,639 |   |
|                                 |       |                                                                          |       |   |   |   |   |   |   |   |   |
| **Capital  Expenditures**            |       | $                                                                             | 194,887    |   | $ | 2,196 |   | $ | 4,719 |   |   |   | $ | 201,802 |   |
|                                      |            |                                                                               |            |  |  |  |  |  |  |  |  |  |  |  |  |  |

 
| ** **                           | ** ** | **For the twelve months ended March 31,  2007** | ** ** |
|--------------------------------------|------------|-------------------------------------------------------------------------------|------------|
| **($-000’s)**                   | ** ** | **Electric**                                                                  | ** ** | **Gas (1)** | ** ** | **Other** | ** ** | **Eliminations** | ** ** | **Total** | ** ** |
| **Statement  of Income Information** |       |                                                                          |       |   |   |   |   |   |   |   |   |
| Revenues                             |       | $                                                                             | 398,769    |   | $ | 52,735 |   | $ | 3,055 |   | $ | (398 | ) | $ | 454,161 |   |
| Depreciation and  amortization       |       | 39,467                                                                        |       | 1,531 |   | 898 |   | — |   | 41,896 |   |
| Federal and  state income taxes      |       | 21,957                                                                        |       | 432 |   | 40 |   | — |   | 22,429 |   |
| Operating income                     |       | 67,816                                                                        |       | 3,890 |   | 704 |   |   |   | 72,410 |   |
| Interest income                      |       | 1,138                                                                         |       | 77 |   | — |   | (819 | ) | 396 |   |
| Interest expense                     |       | 31,962                                                                        |       | 3,338 |   | 687 |   | (819 | ) | 35,168 |   |
| Income from  AFUDC (debt and equity) |       | 5,728                                                                         |       | 78 |   | — |   | — |   | 5,806 |   |
| Income from  continuing operations   |       | 41,725                                                                        |       | 703 |   | 17 |   |   |   | 42,445 |   |
|                                 |       |                                                                          |       |   |   |   |   |   |   |   |   |
| **Capital  Expenditures(2)**         |       | $                                                                             | 136,226    |   | $ | 1,140 |   | $ | 2,634 |   |   |   | $ | 140,000 |   |
|                                      |            |                                                                               |            |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

----

(1)          Represents themonths of June 2006 through March 2007.

(2)          Does not includethe acquisition of the Missouri gas operations.

 

26

----

 
| ** **                     | ** ** | **As of March 31, 2008** | ** ** |
|--------------------------------|------------|--------------------------|------------|
| **($-000’s)**             | ** ** | **Electric**             | ** ** | **Gas(1)** | ** ** | **Other** | ** ** | **Eliminations** | ** ** | **Total** | ** ** |
| **Balance  Sheet Information** |       |                     |       |   |   |   |   |   |   |   |   |
| Total assets                   |       | $                        | 1,442,228  |   | $ | 127,557 |   | $ | 22,178 |   | $ | (76,975 | ) | $ | 1,514,988 |   |
|                                |            |                          |            |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

----

(1) Includes goodwill of $39,492.

 
| ** **                     | ** ** | **As of December 31, 2007** | ** ** |
|--------------------------------|------------|-----------------------------|------------|
| **($-000’s)**             | ** ** | **Electric**                | ** ** | **Gas(1)** | ** ** | **Other** | ** ** | **Eliminations** | ** ** | **Total** | ** ** |
| **Balance  Sheet Information** |       |                        |       |   |   |   |   |   |   |   |   |
| Total assets                   |       | $                           | 1,395,289  |   | $ | 121,918 |   | $ | 22,101 |   | $ | (66,234 | ) | $ | 1,473,074 |   |
|                                |            |                             |            |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

----

(1) Includes goodwill of $39,492.

 

**Note 12–Discontinued Operations**

 

In August 2006, we soldour controlling 52% interest in MAPP, a company that specialized inclose-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 thatmarketed Customer Watch, an Internet-based customer information systemsoftware. On September 28, 2007, we sold our 100% interest in Fast Freedom, Inc.,an Internet service provider. We have reported MAPP, Conversant and FastFreedom’s results as discontinued operations. A summary of the components ofgains or losses from discontinued operations for all periods reported as of March 31,follows:

 

**For the three months ended March 31, 2007**

 
| **($-000’s)**                                       | ** ** | **Fast Freedom** | ** ** | **Total** | ** ** |
|----------------------------------------------------------|------------|-----------------------|------------|-----------|------------|
| Revenues                                                 |       | $                     | 312        |      | $          | 312 |   |
| Expenses                                                 |       | 362                   |       | 362       |       |
| Losses from  discontinued operations before income taxes |       | (50                   | )          | (50       | )          |
| Gain on disposal                                         |       | —                |       | —    |       |
| Income tax                                               |       | 19                    |       | 19        |       |
| Minority  interest                                       |       | —                |       | —    |       |
| Income tax –  minority interest                     |       | —                |       | —    |       |
| **Gain  (loss) from discontinued operations**            | ** ** | **$**                 | **(31**    | **)**     | **$**      | **(31** | **)** |

 

**For the twelve months ended March 31, 2008**

 
| **($-000’s)**                                       | ** ** | **Fast Freedom** | ** ** | **Total**  | ** ** |
|----------------------------------------------------------|------------|-----------------------|------------|------------|------------|
| Revenues                                                 |       | $                     | 593        |       | $          | 593 |   |
| Expenses                                                 |       | 701                   |       | 701        |       |
| Losses from  discontinued operations before income taxes |       | (108                  | )          | (108       | )          |
| Gain on disposal                                         |       | 161                   |       | 161        |       |
| Income tax                                               |       | 41                    |       | 41         |       |
| Minority  interest                                       |       | —                |       | —     |       |
| Income tax –  minority interest                     |       | —                |       | —     |       |
| **Gain  (loss) from discontinued operations**            | ** ** | **$**                 | **94**     | ** ** | **$**      | **94** | ** ** |

 

27

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**For the twelve months ended March 31, 2007**

 
| ** **                                                          | ** ** | **MAPP** | ** ** | **Conversant** | ** ** | **Fast Freedom** | ** ** | **Total** | ** ** |
|---------------------------------------------------------------------|------------|----------|------------|----------------|------------|-----------------------|------------|-----------|------------|
| Revenues                                                            |       | $        | 5,235      |           | $          | 1,488                 |       | $         | 1,330      |   | $ | 8,053 |   |
| Expenses                                                            |       | 5,542    |       | 2,848          |       | 1,595                 |       | 9,985     |       |
| Earnings  (losses) from discontinued operations before income taxes |       | (307     | )          | (1,360         | )          | (265                  | )          | (1,932    | )          |
| Gain on disposal                                                    |       | 272      |       | 555            |       | —                |       | 827       |       |
| Income tax                                                          |       | 117      |       | 518            |       | 102                   |       | 737       |       |
| Minority  interest                                                  |       | 147      |       | —         |       | —                |       | 147       |       |
| Income tax –  minority interest                                |       | (56      | )          | —         |       | —                |       | (56       | )          |
| **Gain  (loss) from discontinued operations**                       | ** ** | **$**    | **173**    | ** **     | **$**      | **(287**              | **)**      | **$**     | **(163**   | **)** | **$** | **(277** | **)** |

 

**Note 13–FAS 157 – Fair Value Measurements**

 

InSeptember 2006, Statement of Financial Accounting Standards (SFAS) No. 157,“Fair Value Measurements,” (FAS 157) was issued. This statement defines fairvalue, establishes a framework for measuring fair value in generally acceptedaccounting principles and expands disclosures about fair value measurements.This statement applies under other accounting pronouncements that require orpermit fair value measurements. FASB Staff Position (FSP) 157-1, issued in February 2008,amended FAS 157 to exclude FASB Statement No. 13, “Accounting for Leases”(FAS 13) and other FAS 157 accounting pronouncements that address fair valuemeasurements for purposes of lease classification or measurement under FAS 13.FASB Staff Position (FSP) 157-2 amended FAS 157 to delay the effective date ofFAS 157 for all nonfinancial assets and nonfinancial liabilities to fiscalyears beginning after November 15, 2008.

 

Theadoption of FAS 157 for financial assets and financial liabilities, effective January 1,2008 did not have a material impact on our consolidated financial position,results of operations and cash flows. We are evaluating the effect the adoptionof FAS 157 for nonfinancial assets and nonfinancial liabilities will have onour consolidated financial position, results of operations and cash flows.

 

FAS157 establishes a three-tier fair value hierarchy, which prioritizes the inputsused in measuring fair value. These tiers include: (i) Level 1, defined asquoted prices in active markets for identical instruments; (ii) Level 2,defined as inputs other than quoted prices in active markets that are eitherdirectly or indirectly observable; and (iii) Level 3, defined asunobservable inputs in which little or no market data exists, thereforerequiring an entity to develop its own assumptions.

 

Thefollowing fair value hierarchy table presents information about our assetsmeasured at fair value using the market value approach on a recurring basis asof March 31, 2008:

 
| ** **                                | ** ** | **Fair  Value Measurements at Reporting Date Using** | ** ** |
|-------------------------------------------|------------|------------------------------------------------------|------------|
| **($ in 000’s)****Description** | ** ** | **As of  3/31/08**                              | ** ** | **Quoted Prices in  Active Markets for  Identical Assets  (Level 1)** | ** ** | **Significant Other  Observable  Inputs  (Level 2)** | ** ** | **Significant  Unobservable  Inputs  (Level 3)** | ** ** |
| Net derivative  assets*                   |       | $                                                    | 27,626     |   | $ | 4,492 |   | $ | 23,134 |   | — |   |
| Cash and cash  equivalents                |       | 2,515                                                |       | 2,515 |   | — |   | — |   |
|                                           |            |                                                      |            |  |  |  |  |  |  |  |  |  |

----

 

*The only recurringliabilities are derivative related and are netted against the asset amountsshown in the table above.

 

Wedid not have any gains or losses for valuation using significant unobservableinputs.

 

**Note 14– Income Taxes**

 

Weadopted the provisions of FASB Interpretation No. 48, “Accounting for Uncertainty in**Income Taxes,”**on January 1, 2007. We have decreased ourestimate of unrecognized tax benefits during the quarter ended March 31,2008 as a review of certain amended returns by the Joint Committee on Taxationwas completed. The Joint Committee accepted our tax position which led us 

 

28

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to recognize certain taxbenefits previously unrecognized. We do not expect any significant changes toour unrecognized tax benefits over the next twelve months. The reserve balancerelated to unrecognized tax benefits as of March 31, 2008 and December 31,2007 was $219,000 and $328,000, respectively.

 

**Item 2.  Management’s Discussion and Analysis ofFinancial Condition and Results of Operations**

 

**EXECUTIVE SUMMARY**

 

Weoperate our businesses as three segments: electric, gas and other. The****Empire District Electric Company (EDE) is an operatingpublic utility engaged in the generation, purchase, transmission, distributionand sale of electricity in parts of Missouri, Kansas, Oklahoma and Arkansas. Aspart of our electric segment, we also provide water service to three towns inMissouri. The Empire District Gas Company (EDG) is our wholly owned subsidiaryformed to hold the Missouri Gas assets acquired from Aquila, Inc. on June 1,2006. It provides natural gas distribution to customers in 44 communities innorthwest, north central and west central Missouri. Our other segment consistsprimarily of our fiber optics business. During the twelve months ended March 31,2008, 87.4% of our gross operating revenues were provided from sales from ourelectric segment (including 0.4% from the sale of water), 11.9% from our gassegment and 0.7% from our other segment.

 

InAugust 2006, we sold our controlling 52% interest in Mid-America PrecisionProducts (MAPP), which specialized in close-tolerance custom manufacturing. In December 2006,we sold our 100% interest in Conversant, Inc., a software company thatmarketed Customer Watch, an Internet-based customer information systemsoftware. 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 othersegment, have been classified as discontinued operations and are not includedin our segment information.

 

***Electric Segment***

 

Theprimary drivers of our electric operating revenues in any period are: (1) rateswe can charge our customers, (2) weather, (3) customer growth and (4) generaleconomic conditions. The utility commissions in the states in which we operate,as well as the Federal Energy Regulatory Commission (FERC), set the rates whichwe can charge our customers. In order to offset expenses, we depend on ourability to receive adequate and timely recovery of our costs (primarily fueland purchased power) and/or rate relief. We assess the need for rate relief inall of the jurisdictions we serve and file for such relief when necessary.Weather affects the demand for electricity. Very hot summers and very coldwinters increase electric demand, while mild weather reduces demand.Residential and commercial sales are impacted more by weather than industrialsales, which are mostly affected by business needs for electricity and bygeneral economic conditions. Customer growth, which is the growth in the numberof customers, contributes to the demand for electricity. We expect our annualelectric customer growth to range from approximately 1.4% to 1.6% over the nextseveral years. Our electric customer growth for the twelve months ended March 31,2008 was 1.0%. We define electric sales growth to be growth in kWh sales periodover period excluding the impact of weather. The primary drivers of electricsales growth are customer growth and general economic conditions.

 

The primary drivers of our electric operatingexpenses in any period are: (1) fuel and purchased power expense, (2) maintenanceand repairs expense, including repairs following severe weather and plantoutages, (3) taxes and (4) non-cash items such as depreciation andamortization expense. Fuel and purchased power costs are our largest expenseitems. Several factors affect these costs, including fuel and purchased powerprices, plant outages and weather, which drives customer demand. In order tocontrol the price we pay for fuel for electric generation and purchased 

 

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power, we have entered into long and short-term agreements to purchasepower (including wind energy) and coal and natural gas for our energy supply.We currently engage in hedging activities in an effort to minimize our riskfrom volatile natural gas prices.

 

***Gas Segment***

 

Theprimary drivers of our gas operating revenues in any period are: (1) rateswe can charge our customers, (2) weather, (3) customer growth, (4) thecost of natural gas and interstate pipeline transportation charges and (5) generaleconomic 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 andtimely recovery of our costs (primarily commodity natural gas) and/or raterelief. We assess the need for rate relief and file for such relief whennecessary. However, as part of the unanimous stipulation and agreement filedwith the MPSC on March 1, 2006 and approved on April 18, 2006, wehave 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 ouractual cost of natural gas from customers through rate changes, which are madeperiodically (up to four times) throughout the year in response to weatherconditions, natural gas costs and supply demands. Weather affects the demandfor natural gas. Very cold winters increase demand for gas, while mild weatherreduces demand. Due to the seasonal nature of the gas business, revenues andearnings are typically concentrated in the November through March period,which generally corresponds with the heating season. Customer growth, which isthe growth in the number of customers, contributes to the demand for gas. Our gas segment customer contraction for thetwelve months ended March 31, 2008 was 1.8%, which we believe was due tohigher gas prices and general economic conditions. We expect our annual gas customergrowth to be up to 1% over the next several years. We define gas sales growthto be growth in mcf sales excluding the impact of weather. The primary driversof gas sales growth are customer growth and general economic conditions.

 

The primary driver of our gas operatingexpense in any period is the price of natural gas. However, because gaspurchase costs for our gas utility operations are normally recovered from ourcustomers, any change in gas prices does not have a corresponding impact onincome unless such costs are deemed imprudent or causes customers to reduceusage.

 

***Earnings***

 

During the first quarter of 2008, basic anddiluted earnings per weighted average share of common stock were $0.21 ascompared to $0.15 in the first quarter of 2007. For the twelve months ended March 31,2008, basic and diluted earnings per weighted average share of common stockwere $1.14 as compared to $1.44 for the twelve months ended March 31,2007. As reflected in the table below, the primary positive driver for both thefirst quarter of 2008 and the twelve months ended March 31, 2008 wasincreased electric revenues. Increased total electric fuel and purchased powercosts was the primary negative driver for both the first quarter of 2008 andthe twelve months ended March 31, 2008. Increased depreciation was also asignificant negative driver for the twelve months ended March 31, 2008mainly due to $7.8 million of regulatory amortization related to the December 21,2007 Missouri rate order that has been recorded as depreciation expense duringthis period.

 

The following reconciliation of basicearnings per share between the three months and twelve months ended March 31,2007 versus March 31, 2008 is a non-GAAP presentation. We believe thisinformation is useful in understanding the fluctuation in earnings per sharebetween the prior and current years. The reconciliation presents the after taximpact of significant items and components of the statement of operations on aper share basis before the impact of additional stock issuances which ispresented separately. Earnings per share for the three months and twelve monthsended March 31, 2007 and 2008 shown in the reconciliation are presented ona GAAP basis and are the same as the amounts included in the statements ofoperations. This reconciliation may not be comparable to other companies ormore useful than the GAAP presentation included in the statements ofoperations.

 

30

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| ** **                                   | ** ** | **Three Months  Ended** | ** ** | **Twelve Months  Ended** | ** ** |
|----------------------------------------------|------------|------------------------------|------------|-------------------------------|------------|
| **Earnings  Per Share – 2007**          | ** ** | **$**                        | **0.15**   | ** **                    | **$**      | **1.44** | ** ** |
|                                         |       |                         |       |                          |       |
| **Revenues**                                 |       |                         |       |                          |       |
| Electric  on-system                          |       | $                            | 0.17       |                          | $          | 0.64 |   |
| Electric off –  system and other        |       | 0.10                         |       | 0.24                          |       |
| Gas                                          |       | (0.01                        | )          | 0.15                          |       |
| Water                                        |       | 0.00                         |       | 0.00                          |       |
| Non – Regulated                         |       | 0.01                         |       | 0.02                          |       |
| **Expenses**                                 | ** ** | ** **                   | ** ** | ** **                    | ** ** |
| Electric fuel                                |       | (0.14                        | )          | (0.47                         | )          |
| Purchased power                              |       | (0.14                        | )          | (0.37                         | )          |
| Cost of natural  gas sold and transported    |       | 0.02                         |       | (0.06                         | )          |
| Regulated –  electric segment           |       | (0.02                        | )          | (0.14                         | )          |
| Regulated – gas  segment                |       | 0.01                         |       | (0.02                         | )          |
| Non-regulated                                |       | 0.00                         |       | (0.01                         | )          |
| Maintenance and  repairs                     |       | 0.12                         |       | 0.04                          |       |
| Depreciation and  amortization               |       | (0.02                        | )          | (0.26                         | )          |
| Other taxes                                  |       | (0.01                        | )          | (0.05                         | )          |
| Interest charges                             |       | (0.01                        | )          | (0.11                         | )          |
| AFUDC                                        |       | 0.01                         |       | 0.05                          |       |
| Discontinued  operations                     |       | 0.00                         |       | 0.01                          |       |
| Loss on plant  allowance                     |       | 0.00                         |       | 0.02                          |       |
| Gain on sale of  assets                      |       | 0.00                         |       | 0.03                          |       |
| Change in  effective income tax rates        |       | (0.01                        | )          | 0.07                          |       |
| Other income and  deductions                 |       | 0.00                         |       | 0.00                          |       |
| Dilutive effect  of additional shares issued |       | (0.02                        | )          | (0.08                         | )          |
| **Earnings  Per Share – 2008**          | ** ** | **$**                        | **0.21**   | ** **                    | **$**      | **1.14** | ** ** |

 

**RecentActivities**

 

***Amendment of EDE Mortgage***

 

OnMarch 11, 2008, we amended the Indenture of Mortgage and Deed of Trust ofThe Empire District Electric Company (EDE Mortgage) in order to provide us withadditional flexibility to pay dividends to our shareholders by increasing thebasket available to pay dividends by $10.75 million. The amendment followed thesuccessful completion of a solicitation of consents from the holders of ourFirst Mortgage Bonds outstanding under the EDE Mortgage. We received consentsfrom holders of 94.46% in aggregate principal amount of the outstanding bondsand paid fees of approximately $1.6 million to the consenting bondholders. See “—Dividends”below.

 

***Asbury SCR and Maintenance Outage***

 

In order to help meet CAIR requirements, we constructedan SCR at Asbury that was completed in November 2007 and placed in servicein February 2008. The total cost of the SCR project was approximately$31.0 million (excluding AFUDC), of which $28.1 million was expended through December 31,2007 with the remainder expended in 2008. This project was also included as part of our Experimental RegulatoryPlan approved by the MPSC. We combined this project with our five yearAsbury maintenance outage.

 

OurAsbury units went off-line September 21, 2007 and were expected to be backon-line during the last week of November, during which time we expected to tiein the SCR. However, on December 7, 2007, during the reassembly of thegenerator, the unit failed inspection. On December 9, 2007 it wasdetermined that corrective action would be necessary and that additional workwould require the unit to remain on outage an additional 60 days. The unit wasreturned to service on February 10, 2008. We had to replace the energy that would have been generated by ourcoal-fired units at the Asbury plant with energy generated at our gas plantsand with purchased power. After 

 

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assessingthe actual cost of the incremental purchased power and gas-fired generation, weestimate the planned outage added incremental expenses of approximately $8.7million for the fourth quarter of 2007. We estimate the extended outageincreased expenses an additional $3.5 million in the fourth quarter of 2007 (December 8-December 31,2007) and an additional $5.8 million in the first quarter of 2008 (January 1-February 10,2008).

 

***Regulatory Matters***

 

With regard to our 2006 Missouri rate case, on March 19,2007, the Office of Public Counsel (OPC) filed a Petition for Writ of Mandamuswith the Missouri Supreme Court seeking an order requiring the Missouri PublicService Commission (MPSC) to vacate and rescind its December 29, 2006order approving tariffs and directing the MPSC to provide an effective date forany subsequent tariff approval order that allows at least ten days to prepareand file an application for rehearing. On October 30, 2007, the SupremeCourt issued an opinion directing the MPSC to vacate its December 29 orderapproving tariffs and allow the OPC a reasonable time to prepare and file anapplication for rehearing. The Court did not examine the lawfulness orreasonableness of the substance of the MPSC’s December 29, 2006 orderapproving tariffs, and considered only the timing of the issuance of the order.The Court also did not consider the underlying tariffed rates which continue inforce and in effect.

 

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

 

On March 26, 2008, the MPSC issued its OrderGranting Reconsideration of Report and Order, to be effective April 5,2008, and its Report and Order Upon Reconsideration, to be effective April 5,2008, in which the MPSC made additional findings and reaffirmed the rateincrease originally authorized in December of 2006. The OPC andintervenors Praxair and Explorer Pipeline filed applications for rehearingregarding this Report and Order Upon Reconsideration. These applications forrehearing remain pending before the MPSC.

 

Also with regard to the 2006 Missouri rate case, on March 18,2008, the OPC filed a Petition for Writ of Mandamus with the Missouri SupremeCourt to force the MPSC to comply with the Missouri Supreme Court’s opinion andorder of October 30, 2007. The OPC, the MPSC, the intervenors and Empirehave filed written briefs, and oral arguments are scheduled before the MissouriSupreme Court on May 13, 2008.

 

We have filed applications for Accounting AuthorityOrders in Oklahoma and Kansas and have filed a request for storm recovery inArkansas respecting costs incurred due to the two major ice storms in 2007.

 

For additional information, see “Rate Matters”below.

 

**RESULTS OF OPERATIONS**

 

Thefollowing discussion analyzes significant changes in the results of operationsfor the three-month and twelve-month periods ended March 31, 2008,compared to the same periods ended March 31, 2007.

 

The following table represents our results ofoperations by operating segment for the applicable periods ended March 31:

 

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| ** **                         | ** ** | **Three Months Ended** | ** ** | **Twelve Months Ended** | ** ** |
|------------------------------------|------------|----------------------------------|------------|-----------------------------------|------------|
| **(in millions)**                  | ** ** | **2008**                         | ** ** | **2007**                          | ** ** | **2008** | ** ** | **2007** | ** ** |
|                               |       |                             |       |                              |       |   |   |   |   |
| Income from  continuing operations |       |                             |       |                              |       |   |   |   |   |
| Electric                           |       | $                                | 4.4        |                              | $          | 2.8 |   | $ | 33.3 |   | $ | 41.7 |   |
| Gas                                |       | 2.4                              |       | 1.7                               |       | 1.8 |   | 0.7 |   |
| Other                              |       | 0.2                              |       | —                            |       | 0.5 |   | — |   |
| Income from  continuing operations |       | $                                | 7.0        |                              | $          | 4.5 |   | $ | 35.6 |   | $ | 42.4 |   |
| Loss from  discontinued operations |       | —                           |       | —                            |       | 0.1 |   | (0.3 | ) |
| Net income*                        |       | $                                | 7.0        |                              | $          | 4.5 |   | $ | 35.7 |   | $ | 42.2 |   |

 

----

*Differences couldoccur due to rounding.

 

***Electric Segment***

 

**Overview**

 

Our electric segment income for the first quarter of 2008 was $4.4million as compared to $2.8 million for the first quarter of 2007.

 

Electric segment operating revenues comprised approximately 79.4% ofour total operating revenues during the first quarter of 2008. Of our totalelectric operating revenues during the first quarter of 2008, approximately44.9% were from residential customers, 25.7% from commercial customers, 13.7%from industrial customers, 4.7% from wholesale on-system customers, 6.9% fromwholesale off-system transactions and 4.1% from miscellaneous sources,primarily public authorities. The breakdown of our customer classes has notsignificantly changed from the first quarter of 2007.

 

The amounts and percentage changes from the prior periods in kilowatt-hour(“kWh”) sales and operating revenues by major customer class for on-systemsales for the applicable periods ended March 31, were as follows:

 
| ** **           | ** ** | **kWh Sales (in millions)** | ** ** | **kWh Sales (in millions)** | ** ** |
|----------------------|------------|--------------------------------------------|------------|--------------------------------------------|------------|
| ** **           | ** ** | **First**                                  | ** ** | **First**                                  | ** ** | ** ** | ** ** | **12 Months** | ** ** | **12 Months** | ** ** | ** ** | ** ** |
| ** **           | ** ** | **Quarter**                                | ** ** | **Quarter**                                | ** ** | ** ** | ** ** | **Ended** | ** ** | **Ended** | ** ** | ** ** | ** ** |
| ** **           | ** ** | **2008**                                   | ** ** | **2007**                                   | ** ** | **% Change*** | ** ** | **2008** | ** ** | **2007** | ** ** | **% Change*** | ** ** |
| Residential          |       | 593.5                                      |       | 545.2                                      |       | 8.9 | % | 1,978.8 |   | 1,970.0 |   | 0.5 | % |
| Commercial           |       | 379.0                                      |       | 357.8                                      |       | 5.9 |   | 1,632.0 |   | 1,574.6 |   | 3.7 |   |
| Industrial           |       | 262.0                                      |       | 255.4                                      |       | 2.6 |   | 1,116.9 |   | 1,135.1 |   | (1.6 | ) |
| Wholesale  On-System |       | 85.4                                       |       | 80.2                                       |       | 6.6 |   | 347.6 |   | 339.8 |   | 2.3 |   |
| Other**              |       | 32.0                                       |       | 28.0                                       |       | 14.1 |   | 120.7 |   | 114.7 |   | 5.2 |   |
| Total On-System      |       | 1,351.9                                    |       | 1,266.6                                    |       | 6.7 |   | 5,196.0 |   | 5,134.2 |   | 1.2 |   |

 
| ** **           | ** ** | **Operating Revenues  ($ in millions)** | ** ** | **Operating Revenues  ($ in millions)** | ** ** |
|----------------------|------------|--------------------------------------------------------|------------|--------------------------------------------------------|------------|
| ** **           | ** ** | **First**                                              | ** ** | **First**                                              | ** ** | ** ** | ** ** | **12 Months** | ** ** | **12 Months** | ** ** | ** ** | ** ** |
| ** **           | ** ** | **Quarter**                                            | ** ** | **Quarter**                                            | ** ** | ** ** | ** ** | **Ended** | ** ** | **Ended** | ** ** | ** ** | ** ** |
| ** **           | ** ** | **2008**                                               | ** ** | **2007**                                               | ** ** | **% Change*** | ** ** | **2008** | ** ** | **2007** | ** ** | **% Change*** | ** ** |
| Residential          |       | $                                                      | 48.6       |                                                   | $          | 44.7 |   | 8.8 | % | $ | 178.5 |   | $ | 167.2 |   | 6.8 | % |
| Commercial           |       | 27.9                                                   |       | 26.3                                                   |       | 5.9 |   | 130.6 |   | 118.7 |   | 10.0 |   |
| Industrial           |       | 14.8                                                   |       | 14.5                                                   |       | 2.5 |   | 68.1 |   | 65.3 |   | 4.3 |   |
| Wholesale  On-System |       | 5.1                                                    |       | 4.3                                                    |       | 17.9 |   | 19.2 |   | 17.5 |   | 9.5 |   |
| Other**              |       | 2.6                                                    |       | 2.3                                                    |       | 15.2 |   | 10.4 |   | 9.3 |   | 11.9 |   |
| Total On-System      |       | $                                                      | 99.0       |                                                   | $          | 92.1 |   | 7.6 |   | $ | 406.8 |   | $ | 378.0 |   | 7.6 |   |

 

----

**Percentage changes are based on actual kWh sales and revenues and maynot agree to the rounded amounts shown above.*

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

 

33

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***Quarter Ended March 31, 2008 Compared toQuarter Ended March 31, 2007***

 

**Operating Revenues and Kilowatt-Hour Sales**

 

KWh sales for our on-system customers increased during the firstquarter of 2008 as compared to the first quarter of 2007 primarily due tocontinued sales growth and favorable weather. Revenues for our on-systemcustomers increased approximately $7.0 million, or 7.6%. Although the impact ofweather is difficult to estimate, especially in light of the January 2007ice storm, we estimate that weather and other related factors increasedrevenues by approximately $4.7 million in the first quarter of 2008 as comparedto the first quarter of 2007. Total heating degree days (the sum of the numberof degrees that the daily average temperature for each day during that periodwas below 65*°* F) for the first quarter of 2008 were 14.1% morethan the same period last year and 0.4% more than the 30-year average.Continued sales growth contributed an estimated $1.2 million during the firstquarter of 2008 while rate changes also contributed an estimated $1.2 million.

 

The increase in residential and commercial kWh sales and revenuesduring the first quarter of 2008 was primarily due to the colder weatherconditions as compared with 2007 and continued sales growth.

 

Industrial kWh sales and revenues, which are not particularly weather sensitive, increased forthe first quarter of 2008 as compared to the same period in 2007 whenindustrial sales were down mainly due to a pipeline customer running at minimumoutput.

 

On-system wholesale kWh sales increased during the first quarter of2008 reflecting the weather conditions and continued sales growth discussedabove. Revenues associated with these FERC-regulated sales increased more thanthe kWh sales as a result of the fuel adjustment clause applicable to suchsales. This clause permits the distribution to customers of changes in fuel andpurchased power costs.

 

**Off-System Electric Transactions**

 

Inaddition to sales to our own customers, we also sell power to other utilitiesas available and provide transmission service through our system fortransactions between other energy suppliers. See “- Competition” below. Thefollowing table sets forth information regarding these sales and related expensesfor the applicable periods ended March 31:

 
| ** **        | ** ** | **2008**              | ** ** | **2007**              | ** ** |
|-------------------|------------|-----------------------|------------|-----------------------|------------|
| ** **        | ** ** | **Three Months** | ** ** | **Three Months** | ** ** |
| **(in millions)** | ** ** | **Ended**             | ** ** | **Ended**             | ** ** |
| Revenues          |       | $                     | 8.1        |                  | $          | 4.2 |   |
| Expenses          |       | 6.2                   |       | 2.7                   |       |
| Net*              |       | $                     | 1.9        |                  | $          | 1.4 |   |

 

----

**Differences could occur due to rounding.*

 

Revenues increased during the first quarter of 2008 as compared to thefirst quarter of 2007 primarily due to sales facilitated by the SPP EnergyImbalance Services (EIS) market that began on February 1, 2007. Sales fromthis market contributed $3.0 million to our off-system electric revenues in thefirst quarter of 2008 with $2.3 million of related expense as compared to $1.9million of electric revenues in the first quarter of 2007 with $1.0 million ofrelated expense. Total purchase power related expenses are included in ourdiscussion of purchased power costs below.

 

**Operating Revenue Deductions**

 

During the first quarter of 2008, total electric segment operatingexpenses increased approximately $9.6 million (10.8%) compared with the sameperiod last year. Total fuel costs increased approximately $5.8 million (22.9%)while purchased power costs increased approximately $5.7 million (28.3%) duringthe first quarter of 2008. The increase in fuel costs was primarily due toincreased generation by our gas fired units in the first quarter of 2008 (anestimated $8.6 million) 

 

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mainly due to the extended outage at the Asbury plant that lasted intothe first quarter of 2008, as well as an approximately $0.9 million increaseresulting from higher costs for the natural gas we burned in our gas-firedunits. These increased costs were partially offset as a result of the unwindingof future physical natural gas positions in February 2008 that reducedfuel expense by approximately $2.1 million in the first quarter of 2008.Increased coal costs contributed approximately $0.2 million to total fuel costsin the first quarter of 2008. Decreased coal generation, mainly due to theAsbury outage, decreased fuel costs approximately $1.2 million while other fuelcosts decreased approximately $0.6 million. The increase in purchased powercosts primarily reflected higher prices for the power purchased (an estimated$3.8 million) as well as increased purchases on the spot market for replacementenergy (an estimated $1.9 million) in the first quarter mainly due to theextended Asbury outage. After assessingthe actual cost of the incremental purchased power and gas-fired generation, weestimate the extended outage increased expenses an additional $5.8 million inthe first quarter of 2008 (January 1-February 10, 2008). Thenet increase in fuel and purchased power during the first quarter of 2008 ascompared to the same period last year was $11.5 million (25.3%).

 

Regulated – other operating expenses for our electric segment increasedapproximately $0.9 million (6.5%) during the first quarter of 2008 as comparedto the same period in 2007 primarily due to increases of $0.6 million intransmission and distribution expense,****$0.2 millionin other steam power expense, $0.2million in employee health care costs expense,****$0.2million in general labor costs, $0.1 million in meter reading expense, $0.1million in other power expense and small increases in other various expenses.These increases were partially offset by a $0.3 million decrease in employee pension expense and a $0.3million decrease in uncollectible accounts.

 

Maintenance and repairs expense decreased approximately $5.1 million(48.7%) in the first quarter of 2008 primarily due to a $4.9 million decreasein distribution maintenance costs as compared to the first quarter of 2007 whenthere were $4.4 million in additional distribution costs related to the January icestorm. Also contributing to the decrease in the first quarter of 2008 was a$0.7 million decrease in maintenance and repairs expense as compared to thefirst quarter of 2007 when there was a planned maintenance and turbineinspection at the Iatan plant. These decreases were partially offset by a $0.3 million increase in transmission maintenanceexpense and an $0.3 million increase in maintenance expense at the State LineCombined Cycle (SLCC) plant.

 

Depreciation and amortization expense increased approximately $0.8million (6.9%) during the quarter mainly due to increased plant in service. Othertaxes increased approximately $0.4 million during the first quarter of 2008 dueto increased property tax reflecting our additions to plant in service andincreased municipal franchise taxes.

 

***Twelve Months Ended March 31, 2008 Compared toTwelve Months Ended March 31, 2007***

 

**Operating Revenues and Kilowatt-Hour Sales**

 

For the twelve months ended March 31, 2008, kWh sales to ouron-system customers increased 1.2% with the associated revenues increasingapproximately $28.8 million (7.6%). The January 2007 Missouri rateincrease contributed an estimated $31.6 million to revenues while continuedsales growth contributed an estimated $6.2 million. Our electric customergrowth for the twelve months ended March 31, 2008 was 1.0%. Weather andother related factors contributed an estimated $3.6 million. These increaseswere partially offset by the $5.9 million revision to our estimate of unbilledrevenues in the third quarter of 2006 and $6.7 million of Interim Energy Charge(IEC) collected in 2006, neither of which reoccurred in 2007. Residential andcommercial kWh sales and associated revenues increased primarily due tocontinued sales growth while the associated revenues also increased due to theMissouri rate increase. Industrial kWh sales decreased for the twelve monthsended March 31, 2008, due in part to the continued slowdown in thebuilding construction products industry as well as the revision to our estimateof unbilled revenues and corresponding KWhs in the third quarter of 2006 thatdid not reoccur in 2007. Industrial revenues increased, reflecting theaforementioned rate increase. On-system wholesale kWh sales increasedreflecting the continued sales growth discussed above. Revenues associated withthese FERC-

 

35

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regulated sales increased more than the kWh sales as a result of thefuel adjustment clause applicable to such sales.

 

**Off-System Electric Transactions**

 

Inaddition to sales to our own customers, we also sell power to other utilitiesas available and provide transmission service through our system fortransactions between other energy suppliers. The following table sets forthinformation regarding these sales and related expenses for the applicableperiods ended March 31:

 
| ** **        | ** ** | **2008**               | ** ** | **2007**               | ** ** |
|-------------------|------------|------------------------|------------|------------------------|------------|
| ** **        | ** ** | **Twelve Months** | ** ** | **Twelve Months** | ** ** |
| **(in millions)** | ** ** | **Ended**              | ** ** | **Ended**              | ** ** |
| Revenues          |       | $                      | 26.4       |                   | $          | 16.2 |   |
| Expenses          |       | 19.3                   |       | 11.4                   |       |
| Net*              |       | $                      | 7.2        |                   | $          | 4.8 |   |

 

----

**Differences could occur due to rounding.*

 

Revenues less expenses increased during the twelve months ended March 31,2008 as compared to the same period in 2007 primarily due to sales facilitatedby the SPP EIS market that began on February 1, 2007. Sales from thismarket contributed $9.9 million to our off-system electric revenues for thetwelve months ended March 31, 2008 with $7.5 million of related expense ascompared to $1.9 million of electric revenues for the twelvemonths ended March 31, 2007 with $1.0 million of related expense. In addition, in May 2007, we entered into a contract with Kansas City Board ofPublic Utilities (BPU) for the sale of energy and capacity for June throughSeptember of 2007 and 2008. Capacity revenue will total approximately $1.3million each year with the energy portion dependent upon the number of hoursthe contract is utilized by BPU. 2007 revenues from the BPU contractwere approximately $1.8 million. Total purchase power related expenses areincluded in our discussion of purchased power costs below.

 

**Operating Revenue Deductions**

 

During the twelve months ended March 31, 2008, total electricsegment operating expenses increased approximately $45.4 million (13.7%)compared to the year ago period. Total fuel costs increased approximately $21.0million (21.4%) during the twelve months ended March 31, 2008 andpurchased power costs increased $16.8 million (25.2%) during the same period.The increase in fuel costs was primarily due to increased generation by our gasfired units (an estimated $30.1 million) in the first quarter of 2008 andfourth quarter of 2007 mainly due to the extended outage at the Asbury plantand in the second quarter of 2007 due to an outage at the Iatan plant and tothe increase in off-system sales. Also adding to the increase were higher costsfor the natural gas we burned in our gas-fired units (approximately $1.0 million).These increased costs were partially offset as a result of the unwinding offuture physical natural gas positions in February 2008 that reduced fuelexpense by approximately $2.1 million in the first quarter of 2008. Decreasedcoal generation, mainly due to the Asbury outage, decreased fuel costs(approximately $8.4 million) partially offset by increased coal costs(approximately $0.8 million) during the twelve months ended March 31,2008. Other fuel costs decreased approximately $0.4 million. The increase inpurchased power costs primarily reflected higher prices for the power purchased(an estimated $9.7 million) as well as increased purchases on the spot marketfor replacement energy (an estimated $7.0 million) in the first quarter of 2008and fourth quarter of 2007 mainly due to the extended Asbury outage

 

Regulated – other operating expenses increased approximately $6.3million (11.2%) during the twelve months ended March 31, 2008 as comparedto the same period last year due primarily to increases of $1.6 million intransmission and distribution expense,****$1.2 millionin customer accounts expense (which includes an increase of $0.6 million inuncollectible accounts), $1.1 million in 

 

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employee pension expense, $0.7 million in general labor costs. $0.5million in employee health care costs, $0.5 million in other steam powerexpense, $0.3 million in other power expense, $0.3 million in injuries anddamages expense and $0.3 million in regulatory commission expense. Theseincreases were partially offset by a $0.2 million decrease in customerassistance expenses.

 

Maintenance and repairs expense decreased approximately $1.7 million(6.3%) during the twelve months ended March 31, 2008, primarily due to a$2.7 million decrease in distribution maintenance costs as compared to the yearago period when there was a January 2007 ice storm. We had $4.4 million ofincremental costs (and $1.2 million non-incremental tree trimming and laborcosts in the first quarter of 2007) related to the January 2007 ice stormas compared to $1.5 million of incremental costs in the fourth quarter of 2007related to the December ice storm. Also contributing to the decreaseduring the twelve months ended March 31, 2008 was a $0.9 million decreasein maintenance and repairs expense at the Iatan plant as compared to the firstquarter of 2007 when there was a planned maintenance and turbine inspection atthe Iatan plant, a $0.4 million decrease in maintenance and repairs expense atthe State Line plant and a $0.4 million decrease in maintenance repairs expenseat the SLCC plant. These decreases were partially offset by increases of $1.1million in transmission maintenance expense, $0.9 million in maintenance andrepairs expense at the Asbury plant and $0.4 million in maintenance and repairsexpense at the Energy Center.

 

Depreciation and amortization expense increased approximately $11.0million (27.9%) mainly due to $7.8 million regulatory amortization related tothe December 21, 2007 Missouri rate order that has been recorded asdepreciation expense as well as increased plant in service. Other taxesincreased approximately $1.4 million due to increased property taxes reflectingour additions to plant in service and increased municipal franchise taxes.

 

***Gas Segment***

 

**Gas Segment Operating Revenuesand Sales**

 

During the first quarter of2008, our total natural gas revenues were approximately $27.3 million ascompared to $27.6 million in the first quarter of 2007. As a result of a 17.5%overall decrease in our Purchased Gas Adjustment (PGA) Clause during the firstquarter of 2008, revenues were slightly lower in the first quarter of 2008 ascompared to the first quarter of 2007 although sales were higher.

 

For the twelve months ended March 31,2008, our total natural gas revenues were approximately $59.6 million ascompared to $52.7 million for the ten months ended March 31, 2007 (basedon the June 1, 2006 acquisition of EDG). The winter months are high salesmonths for the natural gas business, whose heating season runs from November toMarch of each year.

 

The following tables detail our natural gas sales and revenues for theperiods ended March 31:

 

**Total gas delivered to customers - bcf Sales***

 
| ** **                  | ** ** | **Three Months Ended** | ** ** |
|-----------------------------|------------|----------------------------------|------------|
| ** **                  | ** ** | **2008**                         | ** ** | **2007** | ** ** | **% change** | ** ** |
| Residential                 |       | 1.53                             |       | 1.37 |   | 11.8 | % |
| Commercial                  |       | 0.67                             |       | 0.58 |   | 15.9 |   |
| Industrial                  |       | 0.05                             |       | 0.02 |   | 179.6 |   |
| Public  authorities         |       | 0.02                             |       | 0.01 |   | 27.8 |   |
| Total retail  sales*        |       | 2.27                             |       | 1.98 |   | 14.6 |   |
| Transportation  sales       |       | 1.36                             |       | 1.35 |   | 0.8 |   |
| Total gas  operating sales* |       | 3.63                             |       | 3.33 |   | 9.0 |   |

 

----

**Differencescould occur due to rounding.*

 

37

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| ** **                  | ** ** | **Twelve Months Ended** | ** ** | **Ten Months Ended** | ** ** |
|-----------------------------|------------|-----------------------------------|------------|--------------------------------|------------|
| ** **                  | ** ** | **2008**                          | ** ** | **2007****                     | ** ** |
| Residential                 |       | 3.00                              |       | 2.47                           |       |
| Commercial                  |       | 1.40                              |       | 1.14                           |       |
| Industrial                  |       | 0.11                              |       | 0.05                           |       |
| Public  authorities         |       | 0.03                              |       | 0.03                           |       |
| Total retail  sales*        |       | 4.54                              |       | 3.69                           |       |
| Transportation  sales       |       | 4.30                              |       | 3.57                           |       |
| Total gas  operating sales* |       | 8.84                              |       | 7.26                           |       |

 

----

**Differencescould occur due to rounding.*

***2007 ten months ended salesrepresent the months of June 2006 through March 2007.*

 

**Operating Revenues ($ in millions)***

 
| ** **                    | ** ** | **Three Months Ended** | ** ** |
|-------------------------------|------------|----------------------------------|------------|
| ** **                    | ** ** | **2008**                         | ** ** | **2007** | ** ** | **% change** | ** ** |
| Residential                   |       | $                                | 18.1       |   | $ | 18.6 |   | (2.8 | )% |
| Commercial                    |       | 7.5                              |       | 7.5 |   | (0.6 | ) |
| Industrial                    |       | 0.4                              |       | 0.2 |   | 122.9 |   |
| Public  authorities           |       | 0.2                              |       | 0.2 |   | 10.6 |   |
| Total retail  sales revenues  |       | 26.2                             |       | 26.5 |   | (1.1 | ) |
| Transportation  revenues      |       | 1.0                              |       | 1.0 |   | (5.8 | ) |
| Total gas  operating revenues |       | 27.2                             |       | 27.5 |   | (1.1 | ) |
|                               |            |                                  |            |  |  |  |  |  |  |

 

----

**Revenues exclude forfeiteddiscounts, reconnect fees, miscellaneous service revenues, etc.*

 

**Operating Revenues ($ in millions)***

 
| ** **                    | ** ** | **Twelve Months Ended** | ** ** | **Ten Months Ended** | ** ** |
|-------------------------------|------------|-----------------------------------|------------|--------------------------------|------------|
| ** **                    | ** ** | **2008**                          | ** ** | **2007****                     | ** ** |
| Residential                   |       | $                                 | 38.7       |                           | $          | 34.6 |   |
| Commercial                    |       | 16.5                              |       | 14.6                           |       |
| Industrial                    |       | 1.0                               |       | 0.5                            |       |
| Public  authorities           |       | 0.4                               |       | 0.4                            |       |
| Total retail  sales revenues  |       | 56.6                              |       | 50.1                           |       |
| Transportation  revenues      |       | 2.7                               |       | 2.5                            |       |
| Total gas  operating revenues |       | 59.3                              |       | 52.6                           |       |
|                               |            |                                   |            |                                |            |  |  |

 

----

**Revenues exclude forfeiteddiscounts, reconnect fees, miscellaneous service revenues, etc.*

***2007 ten months ended revenuesrepresent the months of June 2006 through March 2007.*

 

**Gas SegmentOperating Revenue Deductions**

 

During the first quarter of2008, EDG’s cost of natural gas sold and transported was approximately $17.7million as compared to $18.7 million during the first quarter of 2007. For thetwelve months ended March 2008, EDG’s cost of natural gas sold andtransported was approximately $36.6 million as compared to $34.0 million forthe ten months ended March 31, 2007. However, due to purchased natural gascost recovery mechanisms for retail customers, fluctuations in the cost ofnatural gas have little effect on income. Our PGA clause allows us to recoverfrom our customers, subject to routine regulatory review, the cost of purchasedgas supplies, including costs, cost reductions, and related carrying costsassociated with the use of financial instruments to hedge the purchase price ofnatural gas. Our PGA clause had a 17.5% overall decrease in the first quarterof 2008 as compared to the first quarter of 2007.

 

Total other operatingexpenses were $2.5 million for the first quarter of 2008 as compared to $2.9million for the first quarter of 2007. EDG had net income of $2.5 million forthe first quarter of 2008 as compared to $1.7 million for the first quarter of2007.

 

Total other operatingexpenses were $9.9 million for the twelve months ended March 31, 2008. EDGhad net income of $1.8 million for the twelve months ended March 31, 2008.Approximately $1.2 million in transition costs were paid to Aquila, Inc.in 2006 for billing and other transition services. These non-recurring costsended when all services were transitioned by November 1, 2006.

 

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***Other Segment***

 

Our other segment includes leasing of fiberoptics cable and equipment (which we are also using in our own utility operations).The following table represents our results of continuing operations for ourother segment for the applicable periods ended March 31:

 
| ** **                                     | ** ** | **Three Months Ended** | ** ** | **Twelve Months Ended** | ** ** |
|------------------------------------------------|------------|----------------------------------|------------|-----------------------------------|------------|
| **(in millions)**                         | ** ** | **2008**                         | ** ** | **2007**                          | ** ** | **2008** | ** ** | **2007** | ** ** |
| Revenues                                       |       | $                                | 1.1        |                              | $          | 0.8 |   | $ | 3.9 |   | $ | 3.1 |   |
| Expenses                                       |       | 0.9                              |       | 0.8                               |       | 3.4 |   | 3.1 |   |
| Net income  (loss) from continuing operations* |       | $                                | 0.2        |                              | $          | 0.0 |   | $ | 0.5 |   | $ | 0.0 |   |

 

----

**Differences could occur due to rounding.*

 

***Consolidated Company***

 

**Income Taxes**

 

Ourconsolidated provision for income taxes increased approximately $1.5 millionduring the first quarter of 2008 as compared to the same period in 2007 mainlydue to increased income. Our consolidated effective federal and state incometax rate for the first quarter of 2008 was 30.8% as compared to 26.5% for thefirst quarter of 2007. The effective tax rate for the quarter varied in part aswe recognized less tax-related Medicare Part D benefits in the 2008 firstquarter.

 

Ourconsolidated provision for income taxes decreased approximately $6.5 millionduring the twelve months ended March 31, 2008 as compared to twelve monthsended March 31, 2007. Our effective federal and state income tax rate forthe twelve months ended March 31, 2008 was 30.9% as compared to 34.5% forthe same period in 2007. The effective tax rate for the 2008 twelve monthperiod decreased as we recognized increased benefits from the equity componentof AFUDC and expenses related to plant removal costs.

 

**Nonoperating Items**

 

Total allowance for funds used duringconstruction (AFUDC) increased $0.4 million in the first quarter of 2008 ascompared to 2007 and increased $2.3 million during the twelve months ended March 31,2008 as compared to the same period in 2007 due to higher levels ofconstruction in each period.

 

Totalinterest charges on long-term debt increased $1.1 million (16.3%) in the firstquarter of 2008 as compared to 2007 and increased $5.3 million (19.7%) for thetwelve months ended March 31, 2008 as compared to the prior year period.The increases in both periods reflect the interest on the $80 million principalamount of first mortgage bonds we issued March 26, 2007, the proceeds ofwhich were added to our general funds and used to pay down short-termindebtedness incurred, in part, as a result of our on-going constructionprogram. Short-term debt interest decreased $0.5 million in the first quarterof 2008 as compared to 2007 and decreased $0.5 million for the twelve monthsended March 31, 2008 as compared to the prior year period, reflectingdecreased usage of short-term debt in each period.

 

Earningsfrom discontinued operations were approximately $0.1 million in the twelvemonth period ended March 31, 2008 while losses from discontinuedoperations were approximately $0.3 million in the twelve month period ended March 31,2007, which included operations and gains recognized from the sales of MAPP,Conversant and Fast Freedom.

 

**OtherComprehensive Income**

 

The change in the fair value of the effectiveportion of our open gas contracts designated as cash flow hedges for ourelectric business and our interest rate derivative contracts and the gains andlosses on contracts settled during the periods being reported, including thetax effect of these items, are reflected in our Consolidated Statement ofComprehensive Income. This net change is recorded as accumulated othercomprehensive income in the capitalization section of our balance 

 

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sheet and does not affect net income or earnings per share. All ofthese contracts have been designated as cash flow hedges. The unrealized gainsand losses accumulated in other comprehensive income are reclassified to fuel,or interest expense, in the periods in which the hedged transaction is actuallyrealized or no longer qualifies for hedge accounting. No interest ratederivative contracts were open or settled during the periods shown below.

 

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

 
| ** **                                       | ** ** | **Three Months Ended** | ** ** | **Twelve Months Ended** | ** ** |
|--------------------------------------------------|------------|----------------------------------|------------|-----------------------------------|------------|
| **(in millions)**                           | ** ** | **2008**                         | ** ** | **2007**                          | ** ** | **2008** | ** ** | **2007** | ** ** |
| Natural gas  contracts settled (1)               |       | $                                | (0.8       | )                                 | $          | 0.2 |   | $ | (2.6 | ) | $ | (0.2 | ) |
| ** **                                       |       |                             |       |                              |       |   |   |   |   |
| Change in FMV of  open contracts for natural gas |       | $                                | 11.0       |                              | $          | 2.9 |   | $ | 13.3 |   | $ | (4.7 | ) |
| ** **                                       |       |                             |       |                              |       |   |   |   |   |
| Taxes                                            |       | $                                | (3.9       | )                                 | $          | (1.2 | ) | $ | (4.1 | ) | $ | 1.9 |   |
| ** **                                       |       |                             |       |                              |       |   |   |   |   |
| Total change in  OCI – net of tax           |       | $                                | 6.3        |                              | $          | 1.9 |   | $ | 6.6 |   | $ | (3.0 | ) |

 

----

(1)** ***Reflected in fuel expense.*

 

Our average cost for our open financialnatural gas hedges was $5.460/Dth at December 31, 2007 and $5.527/Dth at March 31,2008.

 

**RATE MATTERS**

 

We continually assess the need for raterelief in all of the jurisdictions we serve and file for such relief whennecessary.

 

***Electric Segment***

 

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

 
| ** **           | ** ** | ** **            | ** ** | **Annual**   | ** ** | **Percent**  | ** ** | ** **    | ** **           |
|----------------------|------------|-----------------------|------------|--------------|------------|--------------|------------|---------------|----------------------|
| ** **           | ** ** | **Date**              | ** ** | **Increase** | ** ** | **Increase** | ** ** | **Date**      | ** **           |
| **Jurisdiction**     | ** ** | **Requested**         | ** ** | **Granted**  | ** ** | **Granted**  | ** ** | **Effective** | ** **           |
| Missouri -  Electric |       | February 1, 2006 |       | $            | 29,369,397 |         | 9.96       | %             | January 1, 2007 |   |
|                      |            |                       |            |              |            |              |            |               |                      |  |

 

*Missouri*

 

*2006 RateCase*

 

OnFebruary 1, 2006, we filed a request with the MPSC for an annual increasein base rates for our Missouri electric customers in the amount of $29.5million or 9.63%. We also requested transition from the IEC from an earliercase 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 beterminated, but we may not request the implementation of an energy costrecovery mechanism while the current IEC is effective. The MPSC issued an orderon December 21, 2006 granting us an annual increase of $29.4 million or9.96%, with an effective date of January 1, 2007 and eliminating the IEC.Pursuant to this order, the collected IEC was not refunded. The increaseincluded an authorized return on equity of 10.9% and included our fuel andenergy costs as a component of base electric rates. This order also alloweddeferral of any other postretirement benefits that are different from thoseallowed recovery in this rate case. This treatment is similar to treatmentafforded pension costs in our March 2005 rate case. This

 

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orderalso approved regulatory treatment of additional liabilities arising from theadoption of FAS 158. We also agreed to write off $1 million of the cost of ourEnergy Center 2 construction project. The Missouri jurisdictional portion ofthis agreement resulted in a pre tax write off of $0.8 million in the fourthquarter of 2006.

 

The$29.4 million authorized increase in annual revenues includes $19.4 millionresulting from an increase in base rates and $10.4 million resulting from“regulatory amortization.” The regulatory amortization, which is treated asadditional book depreciation for rate-making purposes and is so reflected inthe financial statements, was granted to provide additional cash flow toenhance the financial support for our current generation expansion plan. Thisregulatory amortization is related to our investment in Iatan 2 and alsoincludes our Riverton V84-3A2 combustion turbine (Unit 12) and the environmentalimprovements and upgrades at Asbury and Iatan 1, all of which are part of theExperimental Regulatory Plan approved by the MPSC subject to subsequentprudency review of actual expenditures. Amounts granted as regulatoryamortization will reduce our rate base used in determining our base rates insubsequent rate cases.

 

On March 19, 2007, the OPC filed a Petition forWrit of Mandamus with the Missouri Supreme Court seeking an order requiring theMPSC to vacate and rescind its December 29, 2006 order approving tariffsand directing the MPSC to provide an effective date for any subsequent tariffapproval order that allows at least ten days to prepare and file an applicationfor rehearing. On October 30, 2007, the Supreme Court issued an opiniondirecting the MPSC to vacate its December 29 order approving tariffs andallow the OPC a reasonable time to prepare and file an application forrehearing. The Court did not examine the lawfulness or reasonableness of thesubstance of the MPSC’s December 29, 2006 order approving tariffs, andconsidered only the timing of the issuance of the order. The Court also did notconsider the underlying tariffed rates which continue in force and in effect.

 

Acting upon the opinion of the Missouri SupremeCourt, the MPSC issued an order on December 4, 2007, effective December 14,2007, vacating the December 29, 2006 order and re-approving the tariffsand the same resulting increase in rates. The OPC and intervenors Praxair, Inc.and Explorer Pipeline Company, filed applications for rehearing with the MPSCregarding this order raising various issues referred to below. Theseapplications for rehearing remain pending before the MPSC.

 

On March 26, 2008, the MPSC issued its OrderGranting Reconsideration of Report and Order, to be effective April 5,2008, and its Report and Order Upon Reconsideration, to be effective April 5,2008, in which the MPSC made additional findings and reaffirmed the rateincrease originally authorized in December of 2006. The OPC andintervenors Praxair and Explorer Pipeline filed applications for rehearingregarding this Report and Order Upon Reconsideration, raising objections tomany of the issues addressed in the order, including but not limited to issuesrelating to return on equity, fuel and purchased power expense and, in the caseof the intervenors, the propriety of regulatory amortization under Missouripublic utility law. These applications for rehearing remain pending before theMPSC.

 

On March 18, 2008, the OPC filed a Petition forWrit of Mandamus with the Missouri Supreme Court, purportedly to force the MPSCto comply with the Missouri Supreme Court’s opinion and order of October 30,2007. The OPC, the MPSC, the intervenors and Empire have filed written briefs. OPCand the intervenors claim, among other things, that the MPSC did not complywith the Court’s order to vacate its rate order of December 29, 2006. Weand the MPSC believe that the MPSC fully complied with the Court’s order. Oralarguments are scheduled before the Missouri Supreme Court on May 13, 2008.

 

*2007 Rate Case*

 

OnOctober 1, 2007, we filed a request with the MPSC for an annual increasein base rates for our Missouri electric customers in the amount of $34.7million, or 10.11%. This request is to allow us to recover our investment inthe new 150-megawatt combustion turbine, Unit 12, at our Riverton Plant,capital expenditures associated with the construction of a selective catalyticreduction system at our Asbury Plant, capital expenditures and expenses relatedto the January and December 2007 ice storms and other changes in ourunderlying costs. We are also requesting implementation of a fuel adjustmentclause in Missouri which would permit the distribution to Missouri customers ofchanges in fuel and purchased power costs.

 

*Kansas*

 

OnApril 29, 2005, we filed a request with the Kansas Corporation Commission(KCC) for an increase in base rates for our Kansas electric customers in theamount of $4,181,078, or 24.64%. On October 4, 2005, we and the KCC Stafffiled a Motion to Approve Joint Stipulated Settlement Agreement (Agreement)with the KCC. The Agreement called for an annual increase in base rates (whichincludes historical fuel costs) for our Kansas electric customers ofapproximately $2,150,000, or 12.67%, the implementation of an Energy CostAdjustment Clause (ECA), a fuel rider that will collect or refund fuel costs inthe future that are above or below the fuel costs included in the base ratesand the adoption of the same depreciation rates approved by the MPSC in our2005 Missouri rate case. In addition, we will be allowed to change ourrecognition of pension costs, deferring the Kansas portion of any costs aboveor below the amount included in this rate case as a regulatory asset orliability. The KCC approved the Agreement on December 9, 2005 with aneffective date of January 4, 2006. Pursuant to the Agreement, we were toseek 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 KCCissued an 

 

41

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orderdenying the request for the approval of our existing natural gas hedgingprogram. All gains or losses related to the financial instruments used to fixthe future price of natural gas will be excluded from recovery through the ECAand future base electric rates in Kansas.

 

We have filed applications for Accounting AuthorityOrders in Oklahoma and Kansas and have filed a request for storm recovery inArkansas respecting costs incurred due to the 2007 ice storms.

 

*GasSegment*

 

OnJune 1, 2006, The Empire District Gas Company acquired the Missourinatural gas distribution operations of Aquila, Inc. (Missouri Gas). TheMissouri Gas properties consist of 44 Missouri communities in northwest, northcentral and west central Missouri. The rates, excluding the cost of gas, arethe same as had been in effect at Aquila, Inc. We agreed in the unanimousstipulation and agreement filed with the MPSC on March 1, 2006 andapproved on April 18, 2006, to not file a rate increase request fornon-gas costs for a period of 36 months following the closing date of theacquisition. We have also agreed to use Aquila Inc.’s current depreciation ratesand were allowed to adopt the pension cost recovery methodology approved in ourelectric Missouri Rate Case effective March 27, 2005.

 

APGA clause is included in our gas rates which allows for the over recovery orunder 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 andsupply demands, rather than in one possibly extreme change per year. The ActualCost Adjustment (ACA) is a scheduled yearly filing with the MPSC filed between October 15and November 4 each year. This filing establishes the amount to berecovered from customers for the over/under recovered yearly amounts. A PGA isincluded in the ACA filing. An optional PGA filing without the ACA can be filedup to three times each year, provided a filing does not occur within 60 days ofa previous filing. Our last ACA filing was completed on October 24, 2007.

 

**COMPETITION**

 

**Electric Segment**

 

*SPP-RTO*

 

OnFebruary 1, 2007, the SPP regional transmission organization (RTO)launched its energy imbalance services market (EIS). With the implementation ofthe SPP RTO EIS market and transmission expansion plans of the SPP RTO, weanticipate that our continued participation in the SPP will provide long-termbenefits to our customers and other stakeholders. Our experience to date in theEIS market indicates that we have received benefits through our participation.Our active participation and assessment of EIS market benefits continues.

 

Ingeneral, the SPP RTO EIS market is providing real time energy for mostparticipating members within the SPP regional footprint. Imbalance energyprices are based on market bids and status/availability of dispatchablegeneration and transmission within the SPP market footprint. In addition toenergy imbalance service, the SPP RTO performs a real time security-constrainedeconomic dispatch of all generation voluntarily offered into the EIS market tothe market participants to also serve the native load.

 

Wewill continue to actively engage with the SPP RTO, other members of the SPP andstaffs of our state commissions to evaluate the impact and value of EIS marketparticipation.

 

OnFebruary 16, 2007, the FERC issued a Final Order No. 890, whichinstituted numerous reforms to its Order 888 open access transmission pro formatariff (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 originalpurpose of remedying undue discrimination for the provision of transmissionservice, (ii) to provide greater specificity in the OATT to reduceopportunities for the exercise of undue 

 

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discrimination,make undue discrimination easier to detect, and facilitate the FERC’senforcement, and (iii) to increase transparency in the rules applicableto planning and use of the transmission system. The FERC’s actions requiredmodifications to the SPP and our OATTs as well as regional and localtransmission planning processes. We and SPP submitted our respective Order 890compliance filings of our OATTs on October 11, 2007. Compliancemodifications to our OATT filing were not material and we anticipate them beingaccepted. The SPP proposed modifications to its regional and local areatransmission planning processes, pursuant to Order 890, in its December 7,2007 FERC filing. An issuance from the FERC on our and SPP’s filings ispending. In December 2007, the FERC issued Order 890A, reconfirming its February Order890.

 

*FERC Market Power Order*

 

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

 

OnMarch 3, 2005, the FERC issued an order commencing an investigation todetermine if we had market power within our control area based on our failureto meet one of the FERC’s wholesale market share screens. We filed responses tothat 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 tobecome effective May 16, 2005, subject to a further compliance filing asdirected in the order. Relying on a series of orders issued since March 17,2006 in other proceedings, the FERC rejected our tariff language and directedus to file revisions to our market-based tariff to provide that service underthe tariff applies only to sales outside our control area. The FERC directed usto make refunds, with interest, by September 15, 2006, which we estimatedto be approximately $0.6 million (excluding interest) covering over a thousandhourly energy sales since May 16, 2005 to numerous counterparties externalto our system for wholesale sales made at market prices above the cost basedprices permitted under the mitigation proposal accepted by FERC. This potentialrefund obligation applies to certain wholesale power sales made “inside” ourservice area at market based rates, even though consumption of the energyoccurred outside our service area. In response to the order, we filed a MotionFor Extension of time and expedited treatment regarding the refund andrequested that such refund be delayed until 15 days after the FERC’s order onour rehearing request. On September 5, 2006, the FERC granted the MotionFor Extension, as requested.

 

OnSeptember 14, 2006, we filed a Request For Rehearing of the FERC’s August 15,2006 order regarding the refund and market power mitigation we had proposed. Werequested a rehearing and a waiver of the refund requirement in its entirety.On April 25, 2008, the FERC issued an Order rejecting our Request ForRehearing and requiring the aforementioned refund to be issued within 15 or 30days of the Order. We are required to make an informational filing of a refundreport to the FERC within 15 days of making the refunds as well as modify ourMarket Based Rate Schedule within 30 days of the Order. We are in the processof finalizing the specific amounts of refund to the applicable counterparties.We estimate the potential refunds with interest to be less than $0.5 million.

 

OnMay 5, 2008, we filed a Motion To Clarify with the FERC regarding the duedate of the ordered refunds. Additionally, we requested the refunds to beplaced in escrow pending a judicial review of the FERC’s order and relatedrefunds. The FERC’s response to the Motion to Clarify and escrow request ispending, as is our decision to seek a judicial review of the legality of theFERC’s order.

 

OnJune 21, 2007, the FERC issued a Final Rule related to Market-BasedRates for Wholesales of Electric Energy, Capacity, and Ancillary Services byPublic Utilities, Order 697, which directly affects our market power assessmentwithin our service area and Request For Rehearing related to the aforementionedpending potential refund. In reaction to the Final Rule, we were required tomodify our Market Based Rate Tariff in the form of a compliance filing to theFERC, which was made on September 17, 2007. The FERC’s ruling on ourcompliance filing is pending. We have implemented revisions to our wholesalepower sales business practices in accordance with the Final Rule. On April 14,2008, the FERC granted a Request for Rehearing on its Final Rule 

 

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forMarket-Based Rates for Wholesale Sales of Electric Energy, Capacity andAncillary Services by Public Utilities – Order 697 A. The revised Order largelyaffirmed, with a few modifications, the initial June 21, 2007 Orderincluding its horizontal and vertical market power screening analysis.

 

*Other FERC Rulemaking*

 

Alsoon June 21, 2007, the FERC issued an Advance Notice of Proposed Rulemaking(ANOPR) on potential reforms to improve operations in organized wholesale powermarkets, such as the SPP RTO in which we participate. The FERC is seekingcomment in the following areas: (i) the role of demand response in theorganized markets, (ii) increasing opportunities for long-term powercontracts, (iii) strengthening market monitoring and (iv) theresponsiveness of RTOs and ISOs to customers and stakeholders.

 

On January 28, 2008, we made a filing at the FERC related tocertain non-rate and ministerial revisions to our currently effective wholesaleOpen Access Transmission Tariff (OATT), which included the elimination ofcertain tariff sections that have become moot in light of our membership in theSPP, as well as correction of the formatting of our OATT for consistency withOrder No. 614.

 

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

 

Gas Segment

 

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

 

**LIQUIDITY AND CAPITALRESOURCES**

 

Weused approximately $61.4 million of cash for regulated capital expendituresduring the first quarter of 2008. Our primary sources of cash flow for theseexpenditures during the first quarter of 2008 were $32.1 million in internallygenerated funds from continuing operations and $41.2 million in short-termborrowings.

 

**CashProvided by Operating Activities**

 

Ournet cash flows provided by continuing operating activities were $32.1 millionduring the first quarter of 2008 as compared to $25.2 million for the firstquarter of 2007. Net income increased $2.5 million. In addition, changes inbalance sheet items, primarily accounts receivable, fuel inventories, prepaidexpenses, deferred charges, and accrued interest and taxes positively impactedcash flow this year compared to last year. These positive effects offset thefirst quarter 2008 $18.1 million decrease in accounts payable, which reflectedthe payment of accrued expenditures for the December 2007 ice storm. 

 

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**CapitalRequirements and Investing Activities**

 

Our capital expenditures totaled approximately $61.4 million during thefirst quarter of 2008 compared to approximately $48.6 million for the sameperiod in 2007. These capital expenditures include AFUDC, capital expendituresto retire assets and benefits from salvage.

 

Ournet cash flows used in investing activities increased $15.3 million during thefirst quarter of 2008 as compared to the first quarter of 2007, primarilyreflecting construction expenditures for Plum Point Unit 1 and Iatan 2, as wellas the payments for the capitalized portion of the December 2007 ice stormwhich were accrued but not paid as of December 31, 2007.

 

A breakdown of the capital expenditures for the quarter ended March 31,2008 is as follows:

 
| **(in millions)**                                                                                    | ** ** | **Capital Expenditures** | ** ** |
|------------------------------------------------------------------------------------------------------|------------|-------------------------------|------------|
| Distribution and  transmission system additions                                                      |       | 12.6                          |       |
| New Generation –  Plum Point Energy Station                                                     |       | 8.9                           |       |
| New Generation –  Iatan 2                                                                       |       | 20.1                          |       |
| Storms (1)                                                                                           |       | 1.2                           |       |
| Additions and  replacements – Asbury                                                            |       | 3.5                           |       |
| Additions and  replacements – Iatan 1                                                           |       | 7.4                           |       |
| Additions and  replacements – State Line Unit 1, SLLC, Riverton, Energy Center and Ozark  Beach |       | 0.3                           |       |
| Gas segment  additions and replacements                                                              |       | 0.4                           |       |
| Transportation                                                                                       |       | 0.1                           |       |
| Other (including  retirements and salvage -net)                                                      |       | 1.3                           |       |
| **Subtotal**                                                                                         |       | 55.8                          |       |
| Other capital  expenditures (primarily fiber optics)                                                 |       | 0.4                           |       |
| **Subtotal  capital expenditures incurred (2)**                                                      |       | 56.2                          |       |
| Change in  capital expenditures accrual (3)                                                          |       | 6.3                           |       |
| Less AFUDC  equity capitalized                                                                       |       | (1.1                          | )          |
| **Total  cash outlay**                                                                               |       | 61.4                          |       |

 

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(1)** **For the first quarter of 2008, storm costs of $0.1 million arespecifically related to capital expenditures associated with the December 2007ice storm.

 

(2) Expenditures incurred represent the totalcost for work completed for the projects during the quarter. Discussion ofcapital expenditures throughout this 10-Q is presented on this basis.

 

(3) The amount of expenditures unpaid at theend of the reporting period and not reflected in the Investing Activitiessection of the Statement of Cash Flows and the reversal of accrued year-endexpenditures, paid in the first quarter of 2008.

 

Approximately35% of our cash requirements for capital expenditures during the first quarterof 2008 were satisfied internally from operations (funds provided by operatingactivities less dividends paid). The remaining amounts of such requirementswere satisfied from short-term borrowings and proceeds from our sales of commonstock and debt securities discussed below.

 

Wecurrently expect that internally generated funds will provide approximately 35%of the funds required for the remainder of our budgeted 2008 capitalexpenditures. We intend to utilize a combination of short-term debt, theproceeds of sales of long-term debt and/or common stock (including common stocksold under our Employee Stock Purchase Plan, our Dividend Reinvestment andStock Purchase Plan, and our 401(k) Plan and ESOP) to finance additionalamounts needed beyond those provided by operating activities for such capitalexpenditures. We will continue to utilize short-term debt as needed to supportnormal operations or other temporary requirements. For further information seeNote 6 of “Notes to Consolidated Financial Statements (Unaudited).”

 

We had estimated ourcapital expenditures for our share of Iatan 2 to be approximately $72.4million, $43.8 million and $33.1 million in 2008, 2009 and 2010, respectively.As a result of KCP&L’s updated forecast, however, we now estimate theseexpenditures to be approximately $72.0 million, $67.5 million and $36.1 millionin 2008, 2009 and 2010, respectively. We had estimated our capital expendituresfor our share of the Iatan 1 environmental upgrades to be approximately $26.7million, $1.4 million and $0.3 million in 2008, 2009 and 2010, respectively, butnow estimate these expenditures to be approximately $25.7 million in 2008 and$17.5 million in 2009 with an in-service date of February 2009.  We had estimated our capital expenditures forthe construction of a combustion turbine previously scheduled to be installedby the summer of 2011 to be approximately $0.2 million, $4.8 million and $17.0million in 2008, 2009 and 2010, respectively. As a result of our delaying thecombustion turbine at least one year, however, we now estimate theseexpenditures to be approximately $0.2 million, $0.0 million, $4.8 million and$17.0 million in 2008, 2009, 2010 and 2011, respectively.

 

 

**FinancingActivities**

 

Ournet cash flows received from financing activities were $29.9 million in 2008compared to $33.1 million in 2007.

 

OnMarch 26, 2007, we issued $80 million principal amount of first mortgagebonds. The net proceeds of approximately $79.1 million, less $0.4 million of legal and other financing fees,were 

 

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addedto our general funds and used to pay down short-term indebtedness incurred, inpart, 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 publicoffering for $23.00 per share. The sale resulted in net proceeds ofapproximately $65.7 million ($69.0 million less issuance costs of $3.3million). The proceeds were added to our general funds and used to paydown short-term indebtedness incurred, in part, as a result of our on-going constructionprogram.

 

Wehave an effective shelf registration statement with the SEC under whichapproximately $174.2 million of our common stock, unsecured debt securities,preference stock and first mortgage bonds remain available for issuance. Ofthis amount, $120 million remains available of the original $200 millionapproved by the MPSC as available for first mortgage bonds. We plan to use aportion of the proceeds from issuances under this shelf to fund a portion ofthe capital expenditures for our new generation projects.

 

OnJuly 15, 2005, we entered into a $150 million unsecured revolving creditfacility until July 15, 2010. Borrowings (other than through commercialpaper) are at the bank’s prime commercial rate or LIBOR plus 100 basis pointsbased on our current credit ratings and the pricing schedule in the line ofcredit facility. On March 14, 2006, we entered into the First Amended andRestated Unsecured Credit Agreement which amends and restates the $150 millionunsecured revolving credit facility. The principal amount of the creditfacility was increased to $226 million, with the additional $76 millionallocated to support a letter of credit issued in connection with ourparticipation in the Plum Point Energy Station project. This extra $76 millionof availability reduces over a four year period in line with the amount ofconstruction expenditures we owe for Plum Point Unit 1 and was $34.0 million asof May 1, 2008. The unallocated credit facility is used for workingcapital, general corporate purposes and to back-up our use of commercial paper.This facility requires our total indebtedness (which does not include our notepayable to the securitization trust) to be less than 62.5% of our totalcapitalization at the end of each fiscal quarter and our EBITDA (defined as netincome plus interest, taxes, depreciation and amortization) to be at least twotimes our interest charges (which includes interest on the note payable to thesecuritization trust) for the trailing four fiscal quarters at the end of eachfiscal quarter. Failure to maintain these ratios will result in an event ofdefault under the credit facility and will prohibit us from borrowing fundsthereunder. As of March 31, 2008, we are in compliance with these ratios.This credit facility is also subject to cross-default if we default on inexcess of $10 million in the aggregate on our other indebtedness. Thisarrangement does not serve to legally restrict the use of our cash in thenormal course of operations. There were no outstanding borrowings under thisagreement at March 31, 2008, however, $74.2 million of the availabilitythereunder was used at such date to back up our outstanding commercial paper.

 

Theprincipal amount of all series of first mortgage bonds outstanding at any onetime 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 DistrictElectric Company (but not its subsidiaries) is subject to the lien of the EDEMortgage.****Restrictions inthe EDE mortgage bond indenture could affect our liquidity. The EDE Mortgagecontains a requirement that for new first mortgage bonds to be issued, our netearnings (as defined in the EDE Mortgage) for any twelve consecutive monthswithin the fifteen months preceding issuance must be two times the annualinterest requirements (as defined in the EDE Mortgage) on all first mortgagebonds then outstanding and on the prospective issue of new first mortgagebonds. Our earnings for the twelve months ended March 31, 2008 wouldpermit us to issue approximately $276.0 million of new first mortgage bondsbased on this test with an assumed interest rate of 6.5%. In addition to theinterest coverage requirement, the EDE Mortgage provides that new bonds must beissued against, among other things, retired bonds or 60% of net propertyadditions. At March 31, 2008, we had retired bonds and net propertyadditions which would enable the issuance of at least $591.6 million principalamount of bonds if the annual interest requirements are met. As of March 31,2008, we are in compliance with all restrictive covenants of the EDE Mortgage.

 

Substantiallyall of the property, plant and equipment of The Empire District Gas Company issubject to the lien of the EDG Mortgage. The EDG Mortgage contains arequirement that for new

 

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firstmortgage bonds to be issued, the amount of such new first mortgage bonds shallnot exceed 75% of the cost of property additions acquired after the date of theMissouri Gas acquisition. At March 31, 2008, we had property additions of$2.8 million, which would enable the issuance of at least $2.1 millionprincipal amount of bonds if the annual interest requirements are met. Themortgage also contains a limitation on the issuance by EDG of debt (includingfirst mortgage bonds, but excluding short-term debt incurred in the ordinarycourse under working capital facilities) unless, after giving effect to suchissuance, EDG’s ratio of EBITDA (defined as net income plus interest, taxes,depreciation, amortization and certain other non-cash charges) to interestcharges for the most recent four fiscal quarters is at least 2.0 to 1.****As of March 31,2008, this test would allow us to issue new 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(1) |       | AAA       |       | Aaa              |       | AAA                                      |       |
| Senior Unsecured  Notes                                  |       | BBB       |       | Baa2             |       | BB+                                      |       |
| Trust Preferred  Securities                              |       | BBB-      |       | Baa3             |       | BB                                       |       |
| Commercial Paper                                         |       | F2        |       | P-2              |       | A-3                                      |       |
| Outlook                                                  |       | Negative  |       | Negative         |       | Stable                                   |       |

 

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(1)** **Insured by a third party insurer.

 

OnSeptember 22, 2005, Standard & Poor’s (S&P), reflecting ourannouncement of our proposed acquisition of Aquila, Inc.’s Missourinatural gas properties, placed our corporate credit rating on credit watch withnegative implications. S&P stated that the acquisition comes in addition toour embarking on a capital spending program that is significantly higher thanhistorical levels and will be partially debt financed. On February 13,2006, S&P removed our corporate credit rating from credit watch, but placedus on negative outlook. S&P also reduced the rating on our commercial paperfrom A-2 to A-3 on February 21, 2006. This reduction made it moredifficult for us to issue commercial paper and, as a result, our short-termdebt during the period from February 21, 2006 to June 30, 2006, wasin the form of borrowings under our revolving credit facility. However,beginning on June 30, 2006, we were able to again issue commercial paperat 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+ fromBBB- and affirmed our short-term rating of A-3. S&P’s downgrade reflectedtheir view that our financial measures will be constrained over the nextseveral years by fuel and power costs that continue to exceed the levelrecoverable in rates, and by our higher-than-historical level of capitalspending, including the acquisition of Missouri Gas. S&P affirmed ourratings on June 8, 2007 with a stable outlook.

 

Moody’saffirmed our ratings on May 13, 2005 and revised their rating outlook onus from negative to stable. On January 24, 2007, Moody’s again affirmedour ratings but changed their rating outlook on us back to negative. The changeto a negative rating outlook reflects Moody’s view on the longer-term prospectsfor our ratings given the sizable capital spending program we have committed tothrough 2010 and the potential for further weakness in our credit metrics thatcould develop during this time. On February 14, 2008, Moody’s placed allof our ratings on review for possible downgrade. Moody’s announced that thereview will consider the cumulative impact that certain negative events,including severe weather and operational disruptions in 2007 and 2008, have hadon our cash flow and overall financial flexibility at the current rating level.The review will also consider the potential for elevated costs related to ourcapital spending plan in 2008. This action, as well as any actual downgrade ofour commercial paper rating from Moody’s, may make it difficult for us to issuecommercial paper. To the extent we are unable to issue commercial paper, wewill need to meet our short-term debt needs through borrowings under ourhigher-cost revolving credit facility.

 

OnDecember 19, 2005, Fitch Ratings initiated coverage and assigned ratings(see table above) with a stable rating outlook. Fitch announced that theirratings reflect our low business risk position as a regulated electric utility,a stable service territory and a seemingly improving regulatory

 

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environmentin 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 theoutcome of our current rate filing and weakness in our projected financialmeasures relative to Fitch guidelines for the rating category. Recent eventsleading to the revision were storm damage in December 2007 and theextended outage of the Asbury baseload coal plant following a failed generatorinspection.

 

**CONTRACTUAL OBLIGATIONS**

 

Our contractual obligationshave not significantly changed at March 31, 2008, compared to December 31,2007.

 

**DIVIDENDS**

 

Holdersof our common stock are entitled to dividends if, as, and when declared by theBoard of Directors, out of funds legally available therefore, subject to theprior rights of holders of any outstanding cumulative preferred stock andpreference stock. Payment of dividends is determined by our Board of Directorsafter considering all relevant factors, including the amount of our retainedearnings (which is essentially our accumulated net income less dividend payouts).As of March 31, 2008 our retained earnings balance was $13.4 million,compared to $17.7 million as of March 31, 2007, after paying out $10.8million in dividends during the first quarter of 2008. A reduction of ourdividend per share, partially or in whole, could have an adverse effect on ourcommon stock price.

 

Our diluted earnings pershare were $0.21 for the quarter ended March 31, 2008 and were $1.09 and$1.39 for the years ended December 31, 2007 and 2006, respectively. Dividendspaid per share were $0.32 for the three months ended March 31, 2008 and$1.28 for each of the years ended December 31, 2007 and 2006.

 

Inaddition, the EDE Mortgage and our Restated Articles contain certain dividendrestrictions. The most restrictive of these is contained in the EDE Mortgage,which provides that we may not declare or pay any dividends (other thandividends payable in shares of our common stock) or make any other distributionon, or purchase (other than with the proceeds of additional common stock financing)any shares of, our common stock if the cumulative aggregate amount thereofafter August 31, 1944 (exclusive of the first quarterly dividend of$98,000 paid after said date) would exceed the sum of $10.75 million and theearned surplus (as defined in the EDE Mortgage) accumulated subsequent to August 31,1944, or the date of succession in the event that another corporation succeedsto our rights and liabilities by a merger or consolidation. On March 11,2008, we amended the EDE Mortgage in order to provide us with more flexibilityto pay dividends to our shareholders by increasing the basket available to paydividends by $10.75 million, as described above. As of March 31, 2008,this restriction did not prevent us from issuing dividends.

 

Inaddition, under certain circumstances, our Junior Subordinated Debentures,8-1/2% Series due 2031, reflected as a note payable to securitizationtrust on our balance sheet, held by Empire District Electric Trust I, anunconsolidated securitization trust subsidiary, may also restrict our abilityto pay dividends on our common stock. These restrictions apply if: (1) wehave knowledge that an event has occurred that would constitute an event ofdefault under the indenture governing these junior subordinated debentures andwe have not taken reasonable steps to cure the event, (2) we are indefault with respect to payment of any obligations under our guarantee relatingto the underlying preferred securities, or (3) we have deferred interestpayments on the Junior Subordinated Debentures, 8-1/2% Series due 2031 orgiven notice of a deferral of interest payments. As of March 31, 2008,there were no such restrictions on our ability to pay dividends.

 

**OFF-BALANCE SHEET ARRANGEMENTS**

 

Wehave no off-balance sheet arrangements that have or are reasonably likely tohave a current or future effect on our financial condition, changes in financialcondition, revenues or

 

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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**

 

See“Item 7 – Managements Discussion and Analysis of Financial Condition andResults of Operations” in our Annual Report Form 10-K for the year ended December 31,2007 for a discussion of our critical accounting policies. There were nochanges in these policies in the quarter ended March 31, 2008.

 

**RECENTLY ISSUED ACCOUNTING STANDARDS**

 

See Note 2 of “Notes to ConsolidatedFinancial Statements (Unaudited)”.

 

**Item 3.  Quantitative and Qualitative Disclosuresabout Market Risk**

 

Market risk is the exposure to a change in the value of a physicalasset or financial instrument, derivative or non-derivative, caused by fluctuationsin market variables such as interest rates or commodity prices. We**handle our commodity market risk in accordance with ourestablished Energy Risk Management Policy, which typically includes enteringinto various derivative transactions. We utilize derivatives to manage our gascommodity market risk and to help manage our exposure resulting from purchasingmost of our natural gas on the volatile spot market for the generation of powerfor our native-load customers. See Note 5 of “Notes to Consolidated FinancialStatements (Unaudited)” for further information.

 

*Interest Rate Risk.*We are exposed to changes ininterest rates as a result of financing through our issuance of commercialpaper and other short-term debt. We manage our interest rate exposure bylimiting our variable-rate exposure (applicable to commercial paper andborrowings under our unsecured credit agreement) to a certain percentage oftotal capitalization, as set by policy, and by monitoring the effects of marketchanges in interest rates.

 

If market interest rates average 1% more in 2008 than in 2007, ourinterest expense would increase, and income before taxes would decrease by lessthan $0.4 million. This amount has been determined by considering the impact ofthe hypothetical interest rates on our highest month-end commercial paperbalance for 2007. These analyses do not consider the effects of the reducedlevel of overall economic activity that could exist in such an environment. Inthe event of a significant change in interest rates, management would likelytake actions to further mitigate its exposure to the change. However, due tothe uncertainty of the specific actions that would be taken and their possibleeffects, the sensitivity analysis assumes no changes in our financial structure.

 

*Commodity Price Risk*. We are exposed to theimpact of market fluctuations in the price and transportation costs of coal,natural gas, and electricity and employ established policies and procedures tomanage the risks associated with these market fluctuations, including utilizingderivatives.

 

We satisfied 58.6% of our2007 generation fuel supply need through coal. Approximately 86% of our 2007coal supply was Western coal. We have contracts and current coal inventoriessufficient to supply fuel for our coal plants through 2010. These contracts andinventories satisfy approximately 94% of our anticipated fuel requirements for2008, 67% for 2009 and 48% for our 2010 requirements for our Asbury andRiverton coal plants. In order to manage our exposure to fuel prices, futurecoal supplies will be acquired using a combination of short-term and long-termcontracts.

 

Weare exposed to changes in market prices for natural gas we must purchase to runour combustion turbine generators. Our natural gas procurement program isdesigned to minimize our risk from volatile natural gas prices. We enter intophysical forward and financial derivative contracts with counterpartiesrelating to our future natural gas requirements that lock in prices (withrespect to predetermined percentages of our expected future natural gas needs)in an attempt to lessen the volatility in our fuel expense and improvepredictability. We expect that increases in gas prices will be partially offsetby realized gains under financial derivative transactions. As of April 18,2008,

 

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92%,or 5.8 million Dths’s, of our anticipated volume of natural gas usage for ourelectric operations for the remainder of 2008 is hedged.

 

Basedon our expected natural gas purchases for our electric operations for the nexttwelve months, if average natural gas prices should increase 10% more than theprice at March 31, 2008, our natural gas expense would increase, andincome before taxes would decrease by approximately $1.2 million based on our April 18,2008 total hedged positions for the next twelve months.

 

Weattempt to mitigate a portion of our natural gas price risk associated with ourgas segment using physical forward purchase agreements, storage and derivativecontracts. As of March 31, 2008, we have 0.1 million Dths in storage onthe three pipelines that serve our customers. This represents 6% of our storagecapacity. Our long-term hedge strategyis to mitigate price volatility for our customers by hedging a minimum of 50%of current year, up to 50% of second year and up to 20% of third year expectedgas usage by the beginning of the ACA year at September 1. However, due to purchased natural gascost recovery mechanisms for our retail customers, fluctuations in the cost ofnatural gas have little effect on income.

 

*Credit Risk*. Credit risk is the risk of financial loss to theCompany if counterparties fail to perform their contractual obligations. Inorder to minimize overall credit risk, we maintain credit policies, includingthe evaluation of counterparty financial condition and the use of standardizedagreements that facilitate the netting of cash flows associated with a singlecounterparty. In addition, certain counterparties make available collateral in theform of cash held as margin deposits as a result of exceeding agreed-uponcredit exposure thresholds or may be required to prepay the transaction.Amounts reported as margin deposit liabilities represent funds we hold thatresult from various trading counterparties exceeding agreed-upon creditexposure thresholds. Amounts reported as margin deposit assets represent fundsheld on deposit by various trading counterparties that resulted from usexceeding agreed-upon credit limits established by the counterparties.

 

Thefollowing table depicts our margin deposit assets and margin depositliabilities at March 31, 2008 and December 31, 2007:

 
| **(in millions)**           | ** ** | **March 31, 2008** | ** ** | **December 31, 2007** | ** ** |
|-----------------------------|------------|------------------------------|------------|---------------------------------|------------|
| Margin deposit  assets      |       | $                            | 3.6        |                            | $          | 6.3 |   |
| Margin deposit  liabilities |       | $                            | 3.6        |                            | $          | — |   |

 

Inaddition, we held a letter of credit from a counterparty in our favor for $6.5million as of March 31, 2008.

 

Wesell electricity and gas and provide distribution and transmission services toa diverse group of customers, including residential, commercial and industrialcustomers. Credit risk associated with trade accounts receivable from energycustomers is limited due to the large number of customers. In addition, weenter into contracts with various companies in the energy industry forpurchases of energy-related commodities, including natural gas in our fuelprocurement process.

 

Ourexposure to credit risk is concentrated primarily within our fuel procurementprocess, as we transact with a smaller, less diverse group of counterpartiesand transactions may involve large notional volumes and potentially volatilecommodity prices. At April 18, 2008, gross credit exposure related tothese transactions totaled $50.4 million, reflecting the unrealized gains forcontracts carried at fair value.

 

**Item 4.   Controls andProcedures**

 

Asof the end of the period covered by this report, an evaluation was carried out,under the supervision and with the participation of our management, includingour Chief Executive Officer and Chief Financial Officer, of the effectivenessof the design and operation of our disclosure controls and procedures (as suchterm is defined in Rule 13a-15(e) of the Securities Exchange Act of1934). Based upon that evaluation, the Chief Executive Officer and Chief FinancialOfficer concluded that our disclosure controls and procedures were effective asof March 31, 2008.

 

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There have been no changes in our internal control over financialreporting that occurred during the first quarter of 2008 that have materiallyaffected, or are reasonably likely to materially affect, our internal controlover financial reporting.

 

**PART II.  OTHER INFORMATION**

 

**Item 1A.  Risk Factors.**

 

There have been no material changes to the factors disclosed in Part I,Item 1-A. Risk Factors in our Annual Report on Form 10-K for the yearended December 31, 2007.

 

**Item 4.  Submission of Matters to a Vote ofSecurity Holders.**

 

(a)                                  The AnnualMeeting of Stockholders was held on April 24, 2008.

 

(b)                                 The following personswere re-elected Directors of Empire to serve until the 2011 Annual Meeting ofStockholders:

 

William L. Gipson (26,323,753 votes for; 599,628 withheld authority).

 

Kenneth R. Allen (26,424,206 votes for; 499,175 withheld authority).

 

Bill D. Helton (26,374,762 votes for; 548,620 withheld authority).

 

The term of office as Director of the following other Directorscontinued after the meeting:   Ross C.Hartley, D. Randy Laney, Julio S. Leon, Myron W. McKinney, B. Thomas Mueller,Mary M. Posner and Allan T. Thoms,

 

(c)                                  Commonstockholders voted to approve ratification of the appointment ofPricewaterhouseCoopers LLP as Empire’s independent registered public accountingfirm for the fiscal year ending December 31, 2008. Passage of the proposalrequired the affirmative vote of a majority of the votes cast. The proposalreceived 26,531,610 votes for and 247,390 votes against.

 

(d)                                 Commonstockholders were also asked to vote upon a non-binding advisory proposal todeclassify our Board of Directors. The proposal received 12,036,642 votes for,1,009,369 votes against, 1,157,832 abstentions and 12,719,539 broker non-votes.

 

**Item5.  Other Information.**

 

Forthe twelve months ended March 31, 2008, our ratio of earnings to fixedcharges was 2.15x.  See Exhibit (12)hereto.

 

**Item 6.  Exhibits.**

 

(a)                                  Exhibits.

 

(10) Thirty-secondSupplemental Indenture, dated March 11, 2008, amending and supplementingthe Indenture of Mortgage and Deed of Trust dated as of September 1, 1944,as amended and supplemented, among the Company, as issuer, and The Bank of     New York Trust Company, N.A.(successor to Harris Trust and Savings Bank) and UMB Bank & Trust,N.A. (successor to State Street Bank and Trust Company of Missouri, N.A.), astrustees (Incorporated by reference to Exhibit 10.1 to Current Report on Form 8-Kdated March 11, 2008 and filed March 12, 2008, File No. 1-3368).

 

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(12)Computation of Ratio ofEarnings to Fixed Charges.

 

(31)(a) Certificationof Chief Executive Officer pursuant to Section 302 of the Sarbanes-OxleyAct of 2002.

 

(31)(b) Certificationof Chief Financial Officer pursuant to Section 302 of the Sarbanes-OxleyAct of 2002.

 

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

 

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

 

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*****Thiscertification accompanies this Report pursuant to Section 906 of theSarbanes-Oxley Act of 2002 and shall not be deemed filed by the Company forpurposes of Section 18 or any other provision of the Securities ExchangeAct of 1934, as amended.

 

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**SIGNATURES**

 

Pursuant to the requirements of the Securities Exchange Act of 1934,the Registrant has duly caused this report to be signed on its behalf by theundersigned thereunto duly authorized.

 
|              | **THE  EMPIRE DISTRICT ELECTRIC COMPANY** |
|-------------------|-------------------------------------------|
|              |                                      | Registrant |
|              |                                      |   |
|              |                                      |   |
| ** **        | **By**                                    | **/s/ Gregory A. Knapp** |
|              |                                      | Gregory A. Knapp |
|              |                                      | Vice President – Finance and Chief Financial Officer |
|              |                                      |   |
|              |                                      |   |
| ** **        | **By**                                    | **/s/ Laurie A. Delano** |
|              |                                      | Laurie A. Delano |
|              |                                      | Controller, Assistant Secretary and Assistant Treasurer |
|              |
| May 8,  2008 |

 

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