Table of Contents

 

 

 

**UNITED STATESSECURITIES 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, 2009**                                                                                                                                                                                                                                                                                                              |
|       |       | ** **                                                                                                                                                                                                                                                                                                                                                           |
|       |       | **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 ELECTRICCOMPANY**

(Exact name of registrant as specified in its charter)

 

| **Kansas**                                  |   | **44-0236370**                        |
|---------------------------------------------|--------|---------------------------------------|
| (State of  Incorporation)                   |   | (I.R.S. Employer  Identification No.) |
| ** **                                  |   |                                  |
| **602 S.  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 xNo o

 

Indicate by checkmark whether the registrant has submitted electronically and posted on itscorporate Web site, if any, every Interactive Data File required to besubmitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 ofthis chapter) during the preceding 12 months (or for such shorter period thatthe registrant was required to submit and post such files). Yes oNo o

 

Indicate by checkmark whether the registrant is a large accelerated filer, an accelerated filer,a non-accelerated filer, or a smaller reporting company. See the definitions of“large accelerated filer,” “accelerated filer” and “smaller reporting company”in Rule 12b-2 of the Exchange Act.

 
| 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 oNo x

 

As of May 1,2009, 34,170,525 shares of common stock were outstanding.

 

 

 

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**THEEMPIRE DISTRICT ELECTRIC COMPANY**

 

**INDEX**

 
| ** **     | ** **                                                                                  | **PAGE** |
|----------------|---------------------------------------------------------------------------------------------|----------|
|           | Forward  Looking Statements                                                                 | 3        |
|           |                                                                                        |     |
| Part I -  | Financial Information:                                                                      | 4        |
|           |                                                                                        |     |
| 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 | 31       |
|           |                                                                                        |     |
|           | Executive  Summary                                                                          | 31       |
|           |                                                                                        |     |
|           | Results  of Operations                                                                      | 33       |
|           |                                                                                        |     |
|           | Rate  Matters                                                                               | 42       |
|           |                                                                                        |     |
|           | Competition                                                                                 | 43       |
|           |                                                                                        |     |
|           | Liquidity and Capital Resources                                                             | 45       |
|           |                                                                                        |     |
|           | Contractual  Obligations                                                                    | 49       |
|           |                                                                                        |     |
|           | Dividends                                                                                   | 49       |
|           |                                                                                        |     |
|           | Off-Balance Sheet Arrangements                                                              | 50       |
|           |                                                                                        |     |
|           | Critical Accounting Policies                                                                | 50       |
|           |                                                                                        |     |
|           | Recently Issued Accounting Standards                                                        | 50       |
|           |                                                                                        |     |
| Item 3.        | Quantitative  and Qualitative Disclosures About Market Risk                                 | 50       |
|           |                                                                                        |     |
| Item 4.        | Controls and  Procedures                                                                    | 52       |
|           |                                                                                        |     |
| Part II - | Other Information:                                                                          |     |
|           |                                                                                        |     |
| Item  1.       | Legal  Proceedings - (none)                                                                 |     |
|           |                                                                                        |     |
| Item 1A.       | Risk Factors                                                                                | 53       |
|           |                                                                                        |     |
| 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                                        | 56       |
|           |                                                                                        |     |
| Item 5.        | Other Information                                                                           | 57       |
|           |                                                                                        |     |
| Item 6.        | Exhibits                                                                                    | 57       |
|           |                                                                                        |     |
|           | Signatures                                                                                  | 58       |

 

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**FORWARD LOOKING STATEMENTS**

 

Certain matters discussed in this quarterly report are“forward-looking statements” intended to qualify for the safe harbor fromliability established by the Private Securities Litigation Reform Act of 1995.Such statements address or may address future plans, objectives, expectationsand events or conditions concerning various matters such as capitalexpenditures, earnings, pension and other costs, competition, litigation, ourconstruction program, our generation plans, our financing plans, potentialacquisitions, rate and other regulatory matters, liquidity and capitalresources and accounting matters. Forward-looking statements may contain wordslike “anticipate”, “believe”, “expect”, “project”, “objective” or similarexpressions to identify them as forward-looking statements. Factors that couldcause actual results to differ materially from those currently anticipated insuch statements include:

 

·                  theamount, terms and timing of rate relief we seek and related matters;

·                  thecost and availability of purchased power and fuel, and the results of ouractivities (such as hedging) to reduce the volatility of such costs;

·                  volatilityin the credit, equity and other financial markets and the resulting impact onour short term debt costs and our ability to issue debt or equity securities,or otherwise secure funds to meet our capital expenditure, dividend andliquidity needs;

·                  theresults of prudency and similar reviews by regulators of costs we incur;

·                  weather,business and economic conditions and other factors which may impact salesvolumes and customer growth;

·                  operationof our electric generation facilities and electric and gas transmission anddistribution systems, including the performance of our joint owners;

·                  thecosts and other impacts resulting from natural disasters, such as tornados andice storms;

·                  theperiodic revision of our construction and capital expenditure plans and costand timing estimates;

·                  legislation;

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

·                  competition,including the regional SPP energy imbalance market;

·                  electricutility restructuring, including ongoing federal activities and potential stateactivities;

·                  theimpact of electric deregulation on off-system sales;

·                  changesin accounting requirements;

·                  othercircumstances affecting anticipated rates, revenues and costs;

·                  thetiming of accretion estimates, and integration costs relating to completed andcontemplated acquisitions and the performance of acquired businesses;

·                  rateregulation, growth rates, discount rate, capital spending rate, terminal valuecalculations and other factors integral to the calculations utilized to testthe impairment of goodwill, in addition to market and economic conditions whichcould adversely affect the analysis and ultimately negatively impact earnings;

·                  matterssuch as the effect of changes in credit ratings on the availability and ourcost of funds;

·                  theperformance of our pension assets and other post employment benefit plan assetsand the resulting impact on our related funding commitments;

·                  interruptionsor changes in our coal delivery, gas transportation or storage agreements orarrangements;

·                  thesuccess of efforts to invest in and develop new opportunities;

·                  costsand effects of legal and administrative proceedings, settlements,investigations and claims; and

·                  ourexposure to the credit risk of our hedging counterparties.

 

All such factors are difficult to predict, containuncertainties that may materially affect actual results, and may be beyond ourcontrol. New factors emerge from time to time and it is not possible formanagement to predict all such factors or to assess the impact of each suchfactor on us.  Any forward-lookingstatement speaks only as of the date on which such statement is made, and we donot undertake any obligation to update any forward-looking statement to reflectevents or circumstances after the date on which such statement is made.

 

We caution you that any forward-looking statements arenot 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.

 

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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,**                                            | ** **  |
| ** **                                                                              | ** ** | **2009**                                                      | ** **  | **2008** | ** ** |
| ** **                                                                              | ** ** | **(000’s except per share amounts)** | ** **  |
| **Operating  revenues:**                                                                |       |                                                          |        |   |   |
| Electric                                                                                | ** ** | **$**                                                         | **106,363** |   | $ | 108,305 |   |
| Gas                                                                                     | ** ** | **28,087**                                                    |        | 27,275 |   |
| Water                                                                                   | ** ** | **424**                                                       |        | 436 |   |
| Other                                                                                   | ** ** | **1,141**                                                     |        | 930 |   |
| ** **                                                                              |       | **136,015**                                                   |        | 136,946 |   |
| **Operating  revenue deductions:**                                                      |       |                                                          |        |   |   |
| Fuel and purchased  power                                                               | ** ** | **46,790**                                                    |        | 56,942 |   |
| Cost of natural  gas sold and transported                                               | ** ** | **19,308**                                                    |        | 17,701 |   |
| Regulated  operating expenses                                                           | ** ** | **17,502**                                                    |        | 17,898 |   |
| Other operating  expenses                                                               | ** ** | **409**                                                       |        | 383 |   |
| Maintenance and  repairs                                                                | ** ** | **7,667**                                                     |        | 5,566 |   |
| Depreciation and  amortization                                                          | ** ** | **12,673**                                                    |        | 13,621 |   |
| Provision for  income taxes                                                             | ** ** | **5,533**                                                     |        | 3,118 |   |
| Other taxes                                                                             | ** ** | **7,478**                                                     |        | 7,158 |   |
| ** **                                                                              |       | **117,360**                                                   |        | 122,387 |   |
|                                                                                    |       |                                                          |        |   |   |
| **Operating  income**                                                                   | ** ** | **18,655**                                                    |        | 14,559 |   |
|                                                                                    |       |                                                          |        |   |   |
| **Other  income and (deductions):**                                                     |       |                                                          |        |   |   |
| Allowance for  equity funds used during construction                                    | ** ** | **1,407**                                                     |        | 1,117 |   |
| Interest income                                                                         | ** ** | **77**                                                        |        | 79 |   |
| Benefit/(provision)  for other income taxes                                             | ** ** | **(76**                                                       | **)**       | 13 |   |
| Other, net                                                                              | ** ** | **78**                                                        |        | (237 | ) |
| ** **                                                                              |       | **1,486**                                                     |        | 972 |   |
| **Interest  charges:**                                                                  |       |                                                          |        |   |   |
| Long-term debt                                                                          | ** ** | **9,634**                                                     |        | 8,072 |   |
| Note payable to  securitization trust                                                   | ** ** | **1,063**                                                     |        | 1,063 |   |
| Short-term debt                                                                         | ** ** | **580**                                                       |        | 531 |   |
| Allowance for  borrowed funds used during construction                                  | ** ** | **(2,196**                                                    | **)**       | (1,348 | ) |
| Other                                                                                   | ** ** | **147**                                                       |        | 223 |   |
| ** **                                                                              |       | **9,228**                                                     |        | 8,541 |   |
| **Net  income**                                                                         | ** ** | **$**                                                         | **10,913**  |   | $ | 6,990 |   |
| Weighted average  number of common shares outstanding - basic                           | ** ** | **34,064**                                                    |        | 33,659 |   |
| Weighted average  number of common shares outstanding - diluted                         | ** ** | **34,098**                                                    |        | 33,688 |   |
| **Total  earnings per weighted average share of common stock — basic and diluted** | ** ** | **$**                                                         | **0.32**    |   | $ | 0.21 |   |
| **Dividends  declared per share of common stock**                                       | ** ** | **$**                                                         | **0.32**    |   | $ | 0.32 |   |

 

*See accompanying Notes to Consolidated Financial Statements.*

 

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**THEEMPIRE DISTRICT ELECTRIC COMPANY**

**CONSOLIDATEDSTATEMENTS OF OPERATIONS (UNAUDITED)**

 
| ** **                                                                                                | ** ** | **Twelve Months Ended**                                           | ** **  |
|-----------------------------------------------------------------------------------------------------------|------------|-----------------------------------------------------------------------------|-------------|
| ** **                                                                                                | ** ** | **March 31,**                                                          | ** **  |
| ** **                                                                                                | ** ** | **2009**                                                                    | ** **  | **2008** | ** ** |
| ** **                                                                                                | ** ** | **(000’s except per share amounts) amounts)** | ** **  |
| **Operating  revenues:**                                                                                  |       |                                                                        |        |   |   |
| Electric                                                                                                  | ** ** | **$**                                                                       | **444,524** |   | $ | 436,554 |   |
| Gas                                                                                                       | ** ** | **66,250**                                                                  |        | 59,563 |   |
| Water                                                                                                     | ** ** | **1,770**                                                                   |        | 1,865 |   |
| Other                                                                                                     | ** ** | **4,688**                                                                   |        | 3,474 |   |
| ** **                                                                                                |       | **517,232**                                                                 |        | 501,456 |   |
| **Operating  revenue deductions:**                                                                        |       |                                                                        |        |   |   |
| Fuel and  purchased power                                                                                 | ** ** | **193,906**                                                                 |        | 202,730 |   |
| Cost of natural  gas sold and transported                                                                 | ** ** | **44,237**                                                                  |        | 36,605 |   |
| Regulated  operating expenses                                                                             | ** ** | **71,522**                                                                  |        | 71,902 |   |
| Other operating  expenses                                                                                 | ** ** | **1,915**                                                                   |        | 1,650 |   |
| Maintenance and  repairs                                                                                  | ** ** | **30,651**                                                                  |        | 26,846 |   |
| Gain on sale of  assets                                                                                   | ** ** | **—**                                                                  |        | (1,241 | ) |
| Depreciation and  amortization                                                                            | ** ** | **52,613**                                                                  |        | 53,523 |   |
| Provision for  income taxes                                                                               | ** ** | **21,543**                                                                  |        | 15,885 |   |
| Other taxes                                                                                               | ** ** | **25,737**                                                                  |        | 25,344 |   |
| ** **                                                                                                |       | **442,124**                                                                 |        | 433,244 |   |
|                                                                                                      |       |                                                                        |        |   |   |
| **Operating  income**                                                                                     | ** ** | **75,108**                                                                  |        | 68,212 |   |
|                                                                                                      |       |                                                                        |        |   |   |
| **Other  income and (deductions):**                                                                       |       |                                                                        |        |   |   |
| Allowance for  equity funds used during construction                                                      | ** ** | **6,218**                                                                   |        | 3,135 |   |
| Interest income                                                                                           | ** ** | **1,055**                                                                   |        | 312 |   |
| Provision for  other income taxes                                                                         | ** ** | **(86**                                                                     | **)**       | (25 | ) |
| Other, net                                                                                                | ** ** | **(1,254**                                                                  | )           | (963 | ) |
| ** **                                                                                                |       | **5,933**                                                                   |        | 2,459 |   |
| **Interest  charges:**                                                                                    |       |                                                                        |        |   |   |
| Long-term debt                                                                                            | ** ** | **37,602**                                                                  |        | 32,249 |   |
| Note payable to  securitization trust                                                                     | ** ** | **4,250**                                                                   |        | 4,250 |   |
| Short-term debt                                                                                           | ** ** | **1,902**                                                                   |        | 2,443 |   |
| Allowance for  borrowed funds used during construction                                                    | ** ** | **(7,436**                                                                  | **)**       | (4,936 | ) |
| Other                                                                                                     | ** ** | **1,077**                                                                   |        | 1,026 |   |
| ** **                                                                                                |       | **37,395**                                                                  |        | 35,032 |   |
| **Income  from continuing operations**                                                                    | ** ** | **43,646**                                                                  |        | 35,639 |   |
| Income from  discontinued operations, net of tax                                                          | ** ** | **—**                                                                  |        | 94 |   |
| **Net  income**                                                                                           | ** ** | **$**                                                                       | **43,646**  |   | $ | 35,733 |   |
| Weighted average  number of common shares outstanding - basic                                             | ** ** | **33,921**                                                                  |        | 31,422 |   |
| Weighted average  number of common shares outstanding — diluted                                      | ** ** | **33,960**                                                                  |        | 31,449 |   |
| Earnings from  continuing operations per weighted average share of common stock— basic and  diluted  | ** ** | **$**                                                                       | **1.29**    |   | $ | 1.14 |   |
| Income from  discontinued operations per weighted average share of common stock — basic  and diluted | ** ** | **$**                                                                       | **—**  |   | $ | 0.00 |   |
| **Total  earnings per weighted average share of common stock — basic and diluted**                   | ** ** | **$**                                                                       | **1.29**    |   | $ | 1.14 |   |
| **Dividends  declared per share of common stock**                                                         | ** ** | **$**                                                                       | **1.28**    |   | $ | 1.28 |   |

 

*See accompanying Notes to Consolidated Financial Statements.*

 

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**THEEMPIRE DISTRICT ELECTRIC COMPANY**

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

** **
| ** **                                                                                                             | ** ** | **Three Months Ended** | ** ** |
|------------------------------------------------------------------------------------------------------------------------|------------|----------------------------------|------------|
| ** **                                                                                                             | ** ** | **March 31,**               | ** ** |
| ** **                                                                                                             | ** ** | **2009**                         | ** ** | **2008** | ** ** |
| ** **                                                                                                             | ** ** | **($-000’s)**               | ** ** |
|                                                                                                                   |       |                             |       |   |   |
| **Net  income**                                                                                                        |       | $                                | 10,913     |   | $ | 6,990 |   |
| Reclassification  adjustments for (gain)/loss included in net income or reclassified to  regulatory asset or liability |       | 4,926                            |       | (860 | ) |
| Net change in  fair market value of open derivative contracts for period                                               |       | (9,333                           | )          | 11,023 |   |
| Income taxes                                                                                                           |       | 1,679                            |       | (3,872 | ) |
|                                                                                                                   |       |                             |       |   |   |
| **Comprehensive  income**                                                                                              |       | $                                | 8,185      |   | $ | 13,281 |   |

** **
| ** **                                                                                                             | ** ** | **Twelve Months Ended** | ** ** |
|------------------------------------------------------------------------------------------------------------------------|------------|-----------------------------------|------------|
| ** **                                                                                                             | ** ** | **March 31,**                | ** ** |
| ** **                                                                                                             | ** ** | **2009**                          | ** ** | **2008** | ** ** |
| ** **                                                                                                             | ** ** | **($-000’s)**                | ** ** |
|                                                                                                                   |       |                              |       |   |   |
| **Net  income**                                                                                                        |       | $                                 | 43,646     |   | $ | 35,733 |   |
| Reclassification  adjustments for (gain)/loss included in net income or reclassified to  regulatory asset or liability |       | 1,913                             |       | (2,633 | ) |
| Net change in  fair market value of open derivative contracts for period                                               |       | (37,749                           | )          | 13,370 |   |
| Income taxes                                                                                                           |       | 13,653                            |       | (4,091 | ) |
|                                                                                                                   |       |                              |       |   |   |
| **Comprehensive  income**                                                                                              |       | $                                 | 21,463     |   | $ | 42,379 |   |

** **

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

 

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**THEEMPIRE DISTRICT ELECTRIC COMPANY**

**CONSOLIDATED BALANCE SHEETS(UNAUDITED)**

 
| ** **                                            | ** ** | **March 31, 2009** | ** ** | **December 31, 2008** | ** ** |
|-------------------------------------------------------|------------|------------------------------|------------|---------------------------------|------------|
| ** **                                            | ** ** | **($-000’s)**           | ** ** |
| **Assets**                                            |       |                         |       |                            |       |
| Plant and property, at original cost:                 |       |                         |       |                            |       |
| Electric                                              |       | $                            | 1,493,518  |                            | $          | 1,485,235 |   |
| Natural gas                                           |       | 56,787                       |       | 56,282                          |       |
| Water                                                 |       | 10,717                       |       | 10,560                          |       |
| Other                                                 |       | 29,015                       |       | 28,481                          |       |
| Construction work in progress                         |       | 319,789                      |       | 289,460                         |       |
|                                                  |       | 1,909,826                    |       | 1,870,018                       |       |
| Accumulated depreciation and amortization             |       | 535,484                      |       | 527,245                         |       |
|                                                  |       | 1,374,342                    |       | 1,342,773                       |       |
|                                                  |       |                         |       |                            |       |
| **Current assets:**                                   |       |                         |       |                            |       |
| Cash and cash equivalents                             |       | 8,040                        |       | 2,754                           |       |
| Accounts receivable — trade, net                 |       | 39,153                       |       | 39,487                          |       |
| Accrued unbilled revenues                             |       | 16,722                       |       | 25,170                          |       |
| Accounts receivable — other                      |       | 14,670                       |       | 19,353                          |       |
| Fuel, materials and supplies                          |       | 45,278                       |       | 54,202                          |       |
| Unrealized gain in fair value of derivative contracts |       | 1,700                        |       | 2,395                           |       |
| Prepaid expenses and other                            |       | 6,027                        |       | 5,675                           |       |
| Regulatory assets                                     |       | 2,669                        |       | 2,033                           |       |
|                                                  |       | 134,259                      |       | 151,069                         |       |
| **Noncurrent assets and deferred charges:**           |       |                         |       |                            |       |
| Regulatory assets                                     |       | 158,576                      |       | 162,026                         |       |
| Goodwill                                              |       | 39,492                       |       | 39,492                          |       |
| Unamortized debt issuance costs                       |       | 11,201                       |       | 9,133                           |       |
| Unrealized gain in fair value of derivative contracts |       | 3,752                        |       | 6,434                           |       |
| Other                                                 |       | 3,203                        |       | 2,919                           |       |
|                                                  |       | 216,224                      |       | 220,004                         |       |
| **Total Assets**                                      |       | $                            | 1,724,825  |                            | $          | 1,713,846 |   |

 

(Continued)

 

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

 

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**THEEMPIRE DISTRICT ELECTRIC COMPANY**

**CONSOLIDATEDBALANCE SHEETS (UNAUDITED) (Continued)**

** **
| ** **                                                                                         | ** ** | **March 31, 2009** | ** ** | **December 31, 2008** | ** ** |
|----------------------------------------------------------------------------------------------------|------------|------------------------------|------------|---------------------------------|------------|
| ** **                                                                                         | ** ** | **($-000’s)**           | ** ** |
| **Capitalization and Liabilities**                                                                 |       |                         |       |                            |       |
| Common stock, $1 par value, 34,136,067 and 33,981,579 shares issued and  outstanding, respectively |       | $                            | 34,136     |                            | $          | 33,982 |   |
| Capital in excess of par value                                                                     |       | 485,726                      |       | 483,443                         |       |
| Retained earnings                                                                                  |       | 13,585                       |       | 13,579                          |       |
| Accumulated other comprehensive loss, net of income tax                                            |       | (4,860                       | )          | (2,132                          | )          |
| **Total common stockholders’ equity**                                                         |       | 528,587                      |       | 528,872                         |       |
|                                                                                               |       |                         |       |                            |       |
| **Long-term debt (net of current portion):**                                                       |       |                         |       |                            |       |
| Note payable to securitization trust                                                               |       | 50,000                       |       | 50,000                          |       |
| Obligations under capital lease                                                                    |       | 279                          |       | 174                             |       |
| First mortgage bonds and secured debt                                                              |       | 387,965                      |       | 312,953                         |       |
| Unsecured debt                                                                                     |       | 248,280                      |       | 248,440                         |       |
| **Total long-term debt**                                                                           |       | 686,524                      |       | 611,567                         |       |
| **Total long-term debt and common stockholders’ equity**                                      |       | 1,215,111                    |       | 1,140,439                       |       |
|                                                                                               |       |                         |       |                            |       |
| **Current liabilities:**                                                                           |       |                         |       |                            |       |
| Accounts payable and accrued liabilities                                                           |       | 40,925                       |       | 69,502                          |       |
| Current maturities of long-term debt                                                               |       | 20,200                       |       | 20,160                          |       |
| Short-term debt                                                                                    |       | 47,250                       |       | 102,000                         |       |
| Customer deposits                                                                                  |       | 9,691                        |       | 9,577                           |       |
| Interest accrued                                                                                   |       | 12,783                       |       | 5,921                           |       |
| Unrealized loss in fair value of derivative contracts                                              |       | 11,223                       |       | 12,276                          |       |
| Taxes accrued                                                                                      |       | 9,865                        |       | 3,174                           |       |
|                                                                                               |       | 151,937                      |       | 222,610                         |       |
| **Commitments and contingencies (Note 7)**                                                         |       |                         |       |                            |       |
|                                                                                               |       |                         |       |                            |       |
| **Noncurrent liabilities and deferred credits:**                                                   |       |                         |       |                            |       |
| Regulatory liabilities                                                                             |       | 68,480                       |       | 66,585                          |       |
| Deferred income taxes                                                                              |       | 176,876                      |       | 173,511                         |       |
| Unamortized investment tax credits                                                                 |       | 2,821                        |       | 2,917                           |       |
| Pension and other postretirement benefit obligations                                               |       | 84,744                       |       | 83,151                          |       |
| Unrealized loss in fair value of derivative contracts                                              |       | 4,151                        |       | 3,302                           |       |
| Other                                                                                              |       | 20,705                       |       | 21,331                          |       |
|                                                                                               |       | 357,777                      |       | 350,797                         |       |
| **Total Capitalization and Liabilities**                                                           |       | $                            | 1,724,825  |                            | $          | 1,713,846 |   |

 

*Seeaccompanying Notes to Consolidated Financial Statements.*

 

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**THEEMPIRE DISTRICT ELECTRIC COMPANY**

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

 
| ** **                                                        | ** ** | **Three Months Ended** | ** ** |
|-------------------------------------------------------------------|------------|----------------------------------|------------|
| ** **                                                        | ** ** | **March 31,**               | ** ** |
| ** **                                                        | ** ** | **2009**                         | ** ** | **2008** | ** ** |
| ** **                                                        | ** ** | **($-000’s)**               | ** ** |
| **Operating  activities:**                                        |       |                             |       |   |   |
| Net income                                                        |       | $                                | 10,913     |   | $ | 6,990 |   |
| **Adjustments  to reconcile net income to cash flows:**           |       |                             |       |   |   |
| Depreciation and  amortization                                    |       | 14,981                           |       | 14,558 |   |
| Pension and  other postretirement benefit costs                   |       | 1,484                            |       | 2,465 |   |
| Deferred income  taxes and unamortized investment tax credit, net |       | 3,883                            |       | (318 | ) |
| Allowance for  equity funds used during construction              |       | (1,407                           | )          | (1,117 | ) |
| Stock  compensation expense                                       |       | 699                              |       | 1,009 |   |
| Non-cash  loss/(gain) on derivatives                              |       | 5,208                            |       | (57 | ) |
| Gain on the sale  of assets                                       |       | (366                             | )          | — |   |
| **Cash  flows impacted by changes in:**                           |       |                             |       |   |   |
| Accounts  receivable and accrued unbilled revenues                |       | 9,586                            |       | 5,497 |   |
| Fuel, materials  and supplies                                     |       | 8,923                            |       | 6,903 |   |
| Prepaid  expenses, other current assets and deferred charges      |       | (2,645                           | )          | 99 |   |
| Accounts payable  and accrued liabilities                         |       | (26,906                          | )          | (18,115 | ) |
| Interest, taxes  accrued and customer deposits                    |       | 13,667                           |       | 12,283 |   |
| Other  liabilities and other deferred credits                     |       | 121                              |       | 1,861 |   |
|                                                              |       |                             |       |   |   |
| **Net  cash provided by operating activities**                    |       | 38,141                           |       | 32,058 |   |
| ** **                                                        | ** ** | ** **                       | ** ** | ** ** | ** ** |
| **Investing  activities:**                                        |       |                             |       |   |   |
| Capital  expenditures — regulated                            |       | (41,391                          | )          | (60,961 | ) |
| Capital  expenditures and other investments — other          |       | (553                             | )          | (429 | ) |
| Proceeds from  the sale of property, plant and equipment          |       | 399                              |       | — |   |
|                                                              |       |                             |       |   |   |
| **Net  cash used in investing activities**                        |       | (41,545                          | )          | (61,390 | ) |
| ** **                                                        | ** ** | ** **                       | ** ** | ** ** | ** ** |
| **Financing  activities:**                                        | ** ** | ** **                       | ** ** | ** ** | ** ** |
| Proceeds from  first mortgage bonds - electric                    |       | 75,000                           |       | — |   |
| Debt financing  costs                                             |       | —                           |       | (2,152 | ) |
| Long-term debt  issuance costs                                    |       | (2,273                           | )          | — |   |
| Proceeds from  issuance of common stock net of issuance costs     |       | 1,652                            |       | 1,688 |   |
| Net short-term  (repayments)/borrowings                           |       | (54,750                          | )          | 41,185 |   |
| Dividends                                                         |       | (10,907                          | )          | (10,770 | ) |
| Other                                                             |       | (32                              | )          | (81 | ) |
|                                                              |       |                             |       |   |   |
| **Net  cash provided by financing activities**                    |       | 8,690                            |       | 29,870 |   |
|                                                              |       |                             |       |   |   |
| **Net  increase in cash and cash equivalents**                    |       | 5,286                            |       | 538 |   |
|                                                              |       |                             |       |   |   |
| **Cash  and cash equivalents at beginning of period**             |       | 2,754                            |       | 4,043 |   |
|                                                              |       |                             |       |   |   |
| **Cash  and cash equivalents at end of period**                   |       | $                                | 8,040      |   | $ | 4,581 |   |

 

*See accompanying Notes to Consolidated Financial Statements.*

 

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**NOTES TO CONSOLIDATED FINANCIALSTATEMENTS (UNAUDITED)**

 

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

 

We operate our businesses as threesegments:  electric, gas and other. TheEmpire District Electric Company (EDE), a Kansas corporation organized in 1909,is an operating public utility engaged in the generation, purchase,transmission, distribution and sale of electricity in parts of Missouri,Kansas, Oklahoma and Arkansas. As part of our electric segment, we also providewater service to three towns in Missouri. The Empire District Gas Company (EDG)is our wholly-owned subsidiary which provides natural gas distribution tocommunities in northwest, north central and west central Missouri. Our othersegment primarily consists of a 100% interest in Empire District IndustriesInc., a subsidiary for our fiber optics business. These businesses are held byour wholly-owned subsidiary, EDE Holdings, Inc. (EDE Holdings).

 

The accompanying interimfinancial statements do not include all disclosures included in the annualfinancial statements and therefore should be read in conjunction with thefinancial statements and notes thereto included in our Annual Report on Form 10-Kfor the fiscal year ended December 31, 2008.

 

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 31,2008. Certain reclassifications have been made to prior year information toconform to the current year presentation.

 

**Note 2- Recently Issued and Proposed Accounting Standards**

 

We adopted Statement ofFinancial Accounting Standards (SFAS) No. 157, “Fair Value Measurements,”(FAS 157) on January 1, 2008. This statement defines fair value,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 accounting pronouncements that address fair valuemeasurements for purposes of lease classification or measurement under FAS 13.The adoption of FAS 157 for financial assets and financial liabilities did nothave a material impact on our consolidated financial position, results ofoperations and cash flows. FASB Staff Position (FSP) 157-2 amended FAS 157 todelay the effective date of FAS 157 for all nonfinancial assets andnonfinancial liabilities to fiscal years beginning after November 15,2008. We adopted this portion of the standard on January 1, 2009. Theadoption of FAS 157 for nonfinancial assets and nonfinancial liabilities didnot have an effect on our 2009 first quarter consolidated financial position,results of operations and cash flows.

 

On December 1, 2007,the FASB issued SFAS No. 141(R) “Business Combinations” (FAS 141(R))and SFAS No. 160, “Noncontrolling Interests in Consolidated FinancialStatements, an amendment of Accounting Research Bulletin (ARB) No. 51”(FAS 160). FAS 141(R) and FAS 160 are effective for business combinationsentered into in fiscal years beginning on or after December 15, 2008. FAS141(R) changes the definitions of a business and a business combination,and will result in more transactions recorded as business combinations. Certainacquired contingencies will be recorded initially at fair value on theacquisition date, transactions and restructuring costs generally will be expensedas incurred and in partial acquisitions, companies generally will record 100percent of the assets and liabilities at fair value, including goodwill. FAS141(R) will not have an effect on our financial statements unless we enterinto future business combinations. FAS 160 will not have an effect on ourfinancial statements unless we obtain or sell a non-controlling interest in asubsidiary.

 

In April 2008, the FASBissued SFAS No. 161 “Disclosure About Derivative Instruments and HedgingActivities, an Amendment of FASB Statement No. 133” (FAS 161). FAS 161enhances the 

 

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current disclosure framework in FAS 133, “Accounting for DerivativeInstruments and Hedging Activities.” FAS 161 is effective for periods beginningafter November 15, 2008. We adopted this statement on January 1,2009. The adoption of FAS 161 did not have a material effect on our financialstatement disclosures (See Note 4 below).

 

In December 2008, theFASB issued FSP SFAS No. 132(R)-1, “Employers’Disclosures about Postretirement Benefit Plan Assets”**(FAS 132 (R)-1) which requires additionaldisclosures related to pension and other postretirement benefit plan assets. FAS 132 (R)-1 will be effective as ofDecember 31, 2009 and requires a separate disclosure of the fair value ofeach major category of plan assets of a defined benefit pension orpostretirement plan. In addition, employers are required to discloseinformation enabling users to understand investment policies and strategies,assess the inputs and valuation techniques used to develop fair valuemeasurements, and to disclose any significant concentrations of risks withinplan assets. We do not expect the adoption of FAS 132(R)-1 to have a materialeffect on our results of operations, financial position or liquidity because itprovides enhanced disclosure requirements only.

 

In April 2009 the FASBissued FSP FAS 157-4 “Determining Fair Value When the Volume and Level ofActivity for the Asset or Liability have Significantly Decreased andIdentifying Transactions That Are Not Orderly” which provides additionalguidance for estimating fair value in accordance with FAS 157, Fair ValueMeasurements, when the volume and level of activity for an asset or liabilityhas decreased significantly. This staff position also provides guidance onidentifying circumstances that indicate that a transaction is not orderly. FSPFAS 157-4 will be effective as of June 30, 2009. The adoption of FSP FAS157-4 will not have a material effect on our results of operations, financialposition or liquidity.

 

In April 2009 the FASBissued FSP FAS 115-2 and FAS 124-2 “Recognition and Presentation ofOther-Than-Temporary Impairments” which changes the other-than-temporaryimpairment guidance in existing Generally Accepted Accounting Principles fordebt securities to provide improved presentation and disclosure ofother-than-temporary impairments of debt securities in the financialstatements. This staff position is effective as of June 30, 2009. We donot expect the adoption of FSP FAS 115-2 and FAS 124-2 to have a materialeffect on our result of operations, financial position or liquidity.

 

In April 2009, the FASBissued FSP FAS No. 107-1 and APB 28-1, “Interim Disclosures about FairValue of Financial Instruments,” which amends FAS No. 107, “Disclosuresabout Fair Value of Financial Instruments,” and APB Opinion No. 28, “InterimFinancial Reporting,” respectively, to require disclosures about fair value offinancial instruments in interim financial statements, in addition to theannual financial statements as already required by FAS No.107. FSP FAS 107-1and APB 28-1 will be required for interim periods ending after June 15,2009. As FSP FAS 107-1 and APB 28-1 provide only disclosure requirements, theapplication of this standard will not have a material impact on our results ofoperations, financial position or liquidity.

 

See Note 1 under “Notes toConsolidated Financial Statements” in our Annual Report on Form 10-K forthe year ended December 31, 2008 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 (in thousands).

 

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**Regulatory Assets and Liabilities**

 
| ** **                                                             | ** ** | **March 31, 2009** | ** ** | **December 31, 2008** | ** ** |
|------------------------------------------------------------------------|------------|------------------------------|------------|---------------------------------|------------|
| **Regulatory  Assets:**                                                |       |                         |       |                            |       |
| Unrecovered  purchase gas costs — gas segment, current            |       | $                            | 697        |                            | $          | 1,791 |   |
| Unrecovered  electric fuel and purchased power costs — current(1) |       | 1,972                        |       | 242                             |       |
| Regulatory  assets, current                                            |       | $                            | 2,669      |                            | $          | 2,033 |   |
| Income taxes                                                           |       | 35,166                       |       | 34,515                          |       |
| Unamortized loss  on reacquired debt                                   |       | 13,160                       |       | 13,490                          |       |
| Unamortized loss  on interest rate derivative                          |       | 2,327                        |       | 2,405                           |       |
| Asbury five-year  maintenance                                          |       | 1,741                        |       | 1,855                           |       |
| Pension and  other postretirement benefits(2)                          |       | 84,185                       |       | 84,926                          |       |
| Ice storm costs                                                        |       | 13,783                       |       | 14,704                          |       |
| Asset retirement  obligation                                           |       | 3,165                        |       | 3,118                           |       |
| Unrecovered  purchased gas costs — gas segment                    |       | 1,033                        |       | 3,787                           |       |
| Unsettled  derivative losses — electric segment                   |       | 1,036                        |       | 1,218                           |       |
| Under recovered  electric fuel and purchased power costs(1)            |       | 1,000                        |       | —                          |       |
| Other                                                                  |       | 1,980                        |       | 2,008                           |       |
| Regulatory  assets, long-term                                          |       | $                            | 158,576    |                            | $          | 162,026 |   |
| **Total**                                                              |       | $                            | 161,245    |                            | $          | 164,059 |   |

** **
| ** **                                                 | ** ** | **March 31, 2009** | ** ** | **December 31, 2008** | ** ** |
|------------------------------------------------------------|------------|------------------------------|------------|---------------------------------|------------|
| **Regulatory  Liabilities:**                               |       |                         |       |                            |       |
| Income taxes                                               |       | $                            | 11,125     |                            | $          | 11,126 |   |
| Unamortized gain  on interest rate derivative              |       | 4,179                        |       | 4,221                           |       |
| Costs of removal                                           |       | 45,901                       |       | 43,713                          |       |
| Pension and  other postretirement benefits(3)              |       | 6,852                        |       | 7,042                           |       |
| Over recovered  electric fuel and purchased power costs(1) |       | —                       |       | 228                             |       |
| Other                                                      |       | 423                          |       | 255                             |       |
| **Total**                                                  |       | $                            | 68,480     |                            | $          | 66,585 |   |

 

----

(1) Primarilyconsists of Missouri over or under recovered fuel and purchased power costs.

(2) Primarilyreflects regulatory assets resulting from the unfunded portion of our pensionand OBEP liabilities and regulatory accounting for EDG acquisition costs.Approximately $0.2 million in pension and other postretirement benefit costshave been recognized since January 1, 2009 to reflect the amortization ofthe regulatory assets that were recorded at the time of the acquisition of theAquila, Inc. gas properties.

(3) Includesthe effect of costs incurred that are more or less than those allowed in ratesfor the Missouri (EDE and EDG) and Kansas (EDE) portion of pension costs andthe Missouri EDE portion of other postretirement benefit costs. Since January 1,2009, regulatory liabilities and corresponding expenses have been reduced byapproximately $0.2 million as a result of ratemaking treatment.

 

There have been no changesto the rate base inclusions, expected recoverability or amortizable lives ofour regulatory assets and liabilities since December 31, 2008.

 

**Note 4— Risk Management andDerivative Financial Instruments**

 

We currently engage inhedging activities in an effort to minimize our risk from volatile natural gasprices. We enter into contracts with counterparties relating to our futurenatural gas requirements that lock in prices (with respect to a range ofpredetermined percentages of our expected future natural gas needs) in anattempt to lessen the volatility in our fuel expense and gain predictability.We recognize that if risk is not timely and adequately balanced or ifcounterparties fail to perform contractual obligations, actual results coulddiffer materially from intended results.

 

All derivative instrumentsare recognized at fair value on the balance sheet with gains and losses fromeffective instruments deferred in other comprehensive income (in stockholders’equity) or a regulatory asset or liability for electric segment instrumentsentered into after September 1, 2008. We record unrealized gains/(losses)on the ineffective portion of our gas hedging activities in “Fuel and purchasedpower” under the Operating Revenue Deductions section of our Statement ofOperations since all of our gas hedging activities are related to stabilizingfuel costs as part of our fuel procurement program and are not speculativeactivities. Risks and uncertainties affecting the determination of fair valueinclude:  market conditions in the energyindustry, especially the effects

 

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ofprice volatility, regulatory and global political environments andrequirements, fair value estimations on longer term contracts, theeffectiveness of the derivative instrument in hedging the change in fair valueof the hedged item, estimating underlying fuel demand and counterparty abilityto perform. If we estimate that we have overhedged forecasted demand, the gain orloss on the overhedged portion will be recognized immediately as fuel andpurchased power expense in our Consolidated Statement of Operations.

 

As of March 31, 2009and December 31, 2008, we have recorded the following assets andliabilities representing the fair value of derivative financial instruments,(in thousands):

 

**ASSET DERIVATIVES**

 
| ** **                                                           | ** ** | ** **                                 | ** ** | **March 31,**  | ** ** | **December 31,** | ** ** |
|----------------------------------------------------------------------|------------|--------------------------------------------|------------|---------------------|------------|-----------------------|------------|
| ** **                                                           | ** ** | ** **                                 | ** ** | **2009**            | ** ** | **2008**              | ** ** |
| ** **                                                           | ** ** | **Balance Sheet Classification** | ** ** | **Fair Value** | ** ** | **Fair Value**   | ** ** |
| **Derivatives designated as hedging  instruments under FAS 133**     |       |                                       |       |                |       |                  |       |
| Natural gas contracts, electric segment                              |       | Current assets                             |       | $                   | 256        |                  | $          | 1,214 |   |
|                                                                 |       | Non-current  assets and deferred charges   |       | 3,752               |       | 6,208                 |       |
|                                                                 |       |                                       |       |                |       |                  |       |
| **Derivatives not designated as hedging  instruments under FAS 133** |       |                                       |       |                |       |                  |       |
| Natural gas contracts, gas segment                                   |       | Current assets                             |       | 1,444               |       | 1,177                 |       |
|                                                                 |       | Non-current assets and deferred charges    |       | —              |       | 226                   |       |
|                                                                 |       |                                       |       |                |       |                  |       |
| Natural gas  contracts, electric segment                             |       | Current assets                             |       | —              |       | 4                     |       |
| **Total  derivatives assets**                                        | ** ** | ** **                                 | ** ** | **$**               | **5,452**  | ** **            | **$**      | **8,829** | ** ** |

 

**LIABILITY DERIVATIVES**

 
| ** **                                                           | ** ** | ** **                                   | ** ** | **March 31,**  | ** ** | **December 31,** | ** ** |
|----------------------------------------------------------------------|------------|----------------------------------------------|------------|---------------------|------------|-----------------------|------------|
| ** **                                                           | ** ** | ** **                                   | ** ** | **2009**            | ** ** | **2008**              | ** ** |
| ** **                                                           | ** ** | **Balance Sheet Classification**   | ** ** | **Fair Value** | ** ** | **Fair Value**   | ** ** |
| **Derivatives designated as hedging  instruments under FAS 133**     |       |                                         |       |                |       |                  |       |
| Natural gas contracts, electric segment                              |       | Current liabilities                          |       | $                   | 7,708      |                  | $          | 6,254 |   |
|                                                                 |       | Non-current liabilities and deferred credits |       | 4,151               |       | 3,282                 |       |
|                                                                 |       |                                         |       |                |       |                  |       |
| **Derivatives not designated as hedging  instruments under FAS 133** | ** ** | ** **                                   | ** ** | ** **          | ** ** | ** **            | ** ** |
| Natural gas contracts, gas segment                                   |       | Current liabilities                          |       | $                   | 2,200      |                  | $          | 4,474 |   |
|                                                                 |       | Non-current liabilities and deferred credits |       | —              |       | 20                    |       |
| Natural gas  contracts, electric segment                             |       | Current liabilities                          |       | 1,315               |       | 1,548                 |       |
| **Total  derivatives liabilities**                                   | ** ** | ** **                                   | ** ** | **$**               | **15,374** | ** **            | **$**      | **15,578** | ** ** |

 

*Electric*

 

A $(4.9) million net of tax,unrealized loss representing the fair market value of our electric segmentderivative contracts treated as cash flow hedges is recognized as AccumulatedOther Comprehensive Income in the capitalization section of the balance sheetas of March 31, 2009. The tax effect of $3.0 million on this loss isincluded in deferred taxes. These amounts will be adjusted cumulatively on amonthly basis during the determination periods, beginning April 1, 2009and ending on September 30, 2011. At the end of each determination period,or if cash flow hedge treatment is discontinued, any realized gain or loss forthat period related to the instrument will be reclassified to fuel expense. Asof March 31, 2009, approximately $7.5 million of unrealized losses areapplicable to financial instruments which will settle within the next twelvemonths.

 

Effective September 1,2008, in conjunction with the implementation of the Missouri fuel adjustmentclause in the July 2008 Missouri Public Service Commission (MPSC) rateorder, the unrealized losses or gains from new cash flow hedges are recorded inregulatory assets or liabilities. This is in accordance with FAS 71, given thatthose regulatory assets and liabilities are probable of recovery through ourfuel adjustment mechanism. Unrealized gains and losses from cash flow hedgesexisting at September 1, 2008 will continue to be recorded throughcomprehensive income. Once settled, the realized gain or loss will be recordedas fuel expense and be subject to the fuel adjustment clause.

 

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The following tables setforth the actual pre-tax gains/(losses) and the mark to market effect ofunsettled positions from the qualified portion of our hedging activities forthe electric segment for each of the periods ended March 31, (inthousands):

 
| **Derivatives in FAS 133 Cash Flow** | ** ** | **Statement of  Operations  Classification of** | ** ** | **Amount of Gain / (Loss) Reclassed from OCI into  Income (Effective portion)** | ** ** |
|---------------------------------------------------------------|------------|-----------------------------------------------------------|------------|-----------------------------------------------------------------------------------------------------------------------------------|------------|
| **Hedging Relationships - Electric**           | ** ** | **Gain / (Loss) on**                       | ** ** | **Three Months Ended**                                                                                                  | ** ** | **Twelve Months Ended** | ** ** |
| **Segment**                                                   | ** ** | **Derivative**                                            | ** ** | **2009**                                                                                                                          | ** ** | **2008** | ** ** | **2009** | ** ** | **2008** | ** ** |
| Commodity  contracts                                          |       | Fuel and purchased power expense                          |       | $                                                                                                                                 | (4,926     | ) | $ | 860 |   | $ | (1,913 | ) | $ | 2,633 |   |
|                                                          |       |                                                      |       |                                                                                                                              |       |   |   |   |   |   |   |
| **Total  Effective - Electric Segment**                       | ** ** | ** **                                                | ** ** | **$**                                                                                                                             | **(4,926** | **)** | **$** | **860** | ** ** | **$** | **(1,913** | **)** | **$** | **2,633** | ** ** |

 
| **Derivatives in FAS 133 Cash Flow** | ** ** | **Statement of**                                         | ** ** | **Amount of Gain / (Loss) Recognized in OCI on  Derivative (Effective portion) ** | ** ** |
|---------------------------------------------------------------|------------|---------------------------------------------------------------|------------|------------------------------------------------------------------------------------------------------------------------------------------|------------|
| **Hedging Relationships - Electric**           | ** ** | **Comprehensive**                                             | ** ** | **Three Months Ended **                                                                                                   | ** ** | **Twelve Months Ended** | ** ** |
| **Segment**                                                   | ** ** | **Income**                                                    | ** ** | **2009**                                                                                                                                 | ** ** | **2008** | ** ** | **2009** | ** ** | **2008** | ** ** |
| Commodity  contracts                                          |       | Net change in fair market value of open derivative  contracts |       | $                                                                                                                                        | (9,333     | ) | $ | 11,023 |   | $ | (37,749 | ) | $ | 13,370 |   |
|                                                          |       |                                                          |       |                                                                                                                                     |       |   |   |   |   |   |   |
| **Total  Effective - Electric Segment**                       | ** ** | ** **                                                    | ** ** | **$**                                                                                                                                    | **(9,333** | **)** | **$** | **11,023** | ** ** | **$** | **(37,749** | **)** | **$** | **13,370** | ** ** |

 

The following table setsforth “mark-to-market” pre-tax gains/(losses) from the ineffective portion ofour hedging activities for the electric segment for each of the periods ended March 31,(in thousands):

 
| **Derivatives in FAS 133 Cash Flow** | ** ** | **Statement of  Operations**         | ** ** | **Amount of Gain / (Loss) Recognized in Income on  Derivative (Ineffective Portion)** | ** ** |
|---------------------------------------------------------------|------------|-------------------------------------------|------------|-----------------------------------------------------------------------------------------------------------------------------------------|------------|
| **Hedging Relationships - Electric**           | ** ** | **Classification of Gain**      | ** ** | **Three Months Ended**                                                                                                        | ** ** | **Twelve Months Ended** | ** ** |
| **Segment**                                                   | ** ** | **/ (Loss) on Derivative** | ** ** | **2009**                                                                                                                                | ** ** | **2008** | ** ** | **2009** | ** ** | **2008** | ** ** |
| Commodity  contracts                                          |       | Fuel and purchased power expense          |       | $                                                                                                                                       | —     |   | $ | 34 |   | $ | (2 | ) | $ | 353 |   |
| **Total  Ineffective - Electric Segment**                     | ** ** | ** **                                | ** ** | **$**                                                                                                                                   | **—** | ** ** | **$** | **34** | ** ** | **$** | **(2** | **)** | **$** | **353** | ** ** |

 

The following tables setforth “mark-to-market” pre-tax gains/(losses) from derivatives not designatedas hedging instruments under FAS 133 for the electric segment for each of theperiods ended March 31, (in thousands):

 
| **Derivatives Not Designated as**           | ** ** | **Balance Sheet  Classification of** | ** ** | **Amount of Gain / (Loss) Recognized on Balance  Sheet** | ** ** |
|------------------------------------------------------------|------------|------------------------------------------------|------------|---------------------------------------------------------------------------------------------|------------|
| **Hedging Instruments Under FAS 133-** | ** ** | **Gain / (Loss) on**            | ** ** | **Three Months Ended**                                                            | ** ** | **Twelve Months Ended** | ** ** |
| **Electric Segment(1)**                               | ** ** | **Derivative**                                 | ** ** | **2009**                                                                                    | ** ** | **2008** | ** ** | **2009** | ** ** | **2008** | ** ** |
|                                                       |       |                                           |       |                                                                                        |       |   |   |   |   |   |   |
| Commodity  contracts                                       |       | Regulatory assets                              |       | $                                                                                           | 182        |   |   |   | $ | (1,036 | ) |   |   |
|                                                       |       | Regulatory liabilities                         |       | $                                                                                           | (2         | ) | $ | — |   | $ | — |   | $ | — |   |
| **Total  Electric Segment**                                | ** ** | ** **                                     | ** ** | **$**                                                                                       | **180**    | ** ** | **$** | **—** | ** ** | **$** | **(1,036** | **)** | **$** | **—** | ** ** |

 
| **Derivatives Not Designated as**                 | ** ** | **Statement of  Operations  Classification of** | ** ** | **Amount of Gain / (Loss) Recognized in Income  on Derivative** | ** ** |
|------------------------------------------------------------------|------------|-----------------------------------------------------------|------------|---------------------------------------------------------------------------------------------------------|------------|
| **Hedging Instruments Under FAS 133- ** | ** ** | **Gain / (Loss) on**                       | ** ** | **Three Months Ended**                                                                        | ** ** | **Twelve Months Ended** | ** ** |
| **Electric Segment(1)**                                     | ** ** | **Derivative**                                            | ** ** | **2009**                                                                                                | ** ** | **2008** | ** ** | **2009** | ** ** | **2008** | ** ** |
|                                                             |       |                                                      |       |                                                                                                    |       |   |   |   |   |   |   |
| Commodity  contracts                                             |       | Fuel and purchased power expense                          |       | $                                                                                                       | 50         |   | $ | 302 |   | $ | (279 | ) | $ | 302 |   |
| **Total  Electric Segment**                                      | ** ** | ** **                                                | ** ** | **$**                                                                                                   | **50**     | ** ** | **$** | **302** | ** ** | **$** | **(279** | **)** | **$** | **302** | ** ** |

 

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(1) As all gas hedging activities are related to stabilizing fuel costs, ifconditions change, such as a planned unit outage, we may need to de-designateand/or unwind some of our previous derivatives designated under FAS 133. Inthis instance, these derivatives would be classified into the category above.

 

We also enter intofixed-price forward physical contracts for the purchase of natural gas, coaland purchased power. These contracts are not subject to the fair valueaccounting of FAS 133 because they are considered to be normal purchases. Wehave a process in place 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.

 

As of April 24, 2009,87% of our anticipated volume of natural gas usage for our electric operationsfor the remainder of year 2009 is hedged, either through physical (2.1 millionDth) or financial contracts (3.2 million Dth), at an average price of $5.950per Dekatherm (Dth). In addition, the following volumes and percentages of ouranticipated volume of natural gas usage for our electric operations for thenext four years are hedged at the following average prices per Dth:

 
| **Year** | ** ** | **% Hedged** | ** ** | **Dth Hedged** | ** ** | **Average Price** | ** ** |
|----------|------------|-------------------|------------|---------------------|------------|------------------------|------------|
|     | 2010(1)    |              | 79         | %                   | 7,025,000  |                   | $          | 6.353 |   |
|     | 2011(1)    |              | 50         | %                   | 4,270,000  |                   | $          | 5.675 |   |
|     | 2012       |              | 14         | %                   | 1,200,000  |                   | $          | 7.295 |   |
|     | 2013       |              | 12         | %                   | 1,200,000  |                   | $          | 7.295 |   |

 

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(1)5 million Dth of the anticipated volume ofnatural gas usage for 2010 and 2011 are hedged through financial derivativecontracts.

 

We utilize the followingprocurement guidelines for our electricsegment:  current year up to 100% ofexpected gas usage, first year minimum of 60%, second year minimum of 40%,third year minimum of 20% and fourth year minimum of 10%, subject to a maximumof 80% of the expected gas usage in any one year.

 

On February 15, 2008,we unwound 992,000 Dth of physical gas contracts originally scheduled fordelivery in July and August of 2010 and 2011. This transactionresulted in a gain of approximately $1.3 million after tax which was recordedas fuel and purchased power expense in the Statement of Operations in the firstquarter of 2008. We believe it is probable that we will take physical deliveryunder the remaining physical gas forward contracts.

 

*Gas*

 

Weattempt to mitigate our natural gas price risk for our gas segment by acombination of (1) injecting natural gas into storage during theoff-heating season months, (2) purchasing physical forward contracts and (3) purchasingfinancial derivative contracts. We target to have 95% of our storage capacityfull by November 1 for the upcoming winter heating season. As the winterprogresses, gas is withdrawn from storage to serve our customers. As of April 24,2009, we had 0.4 million Dths in storage on the three pipelines that serve ourcustomers. This represents 19% of our storage capacity. We have an additional0.7 million Dths hedged through financial derivative contracts. Our long-termhedge strategy is to mitigate price volatility for our customers by hedging aminimum of 50% of current year, up to 50% of second year and up to 20% of thirdyear expected gas usage by the beginning of the Actual Cost Adjustment (ACA) year at September 1. A Purchased GasAdjustment (PGA) clause is included in our rates for our gas segment operations,therefore, we mark to market any unrealized gains or losses and any realizedgains or losses relating to financial derivative contracts to a regulatoryasset or regulatory liability account on our balance sheet.

 

The following table setsforth “mark-to-market” pre-tax gains / (losses) from derivatives not designatedas hedging instruments under FAS 133 for the gas segment for each of theperiods ended March 31, (in thousands).

 

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| **Derivatives Not Designated as** | ** ** | **Balance Sheet  Classification of** | ** ** | **Amount of Gain / (Loss) Recognized on  Balance Sheet** | ** ** |
|--------------------------------------------------|------------|------------------------------------------------|------------|---------------------------------------------------------------------------------------------|------------|
| **Hedging Instruments Under FAS** | ** ** | **Gain or (Loss)**                   | ** ** | **Three Months Ended**                                                            | ** ** | **Twelve Months Ended** | ** ** |
| **133 – Gas Segment**        | ** ** | **on Derivative**                         | ** ** | **2009**                                                                                    | ** ** | **2008** | ** ** | **2009** | ** ** | **2008** | ** ** |
|                                             |       |                                           |       |                                                                                        |       |   |   |   |   |   |   |
| Commodity  contracts                             |       | Regulatory assets                              |       | $                                                                                           | (1,839     | ) | $ | 1,210 |   | $ | (11,102 | ) | $ | 1,210 |   |
|                                             |       |                                           |       |                                                                                        |       |   |   |   |   |   |   |
| **Total -  Gas Segment**                         | ** ** | ** **                                     | ** ** | **$**                                                                                       | **(1,839** | **)** | **$** | **1,210** | ** ** | **$** | **(11,102** | **)** | **$** | **1,210** | ** ** |

 

*ContingentFeatures*

 

Certain of our derivative instruments containprovisions that require our senior unsecured debt to maintain an investmentgrade credit rating with any relevant credit rating agency. If our debt were tofall below investment grade, it would be in violation of these provisions, andthe counterparties to the derivative instruments could request increasedcollateralization on derivative instruments in net liability positions. Theaggregate fair value of all derivative instruments with the credit-risk-relatedcontingent features that are in a liability position on March 31, 2009 is$4.0 million for which we have posted no collateral in the normal course ofbusiness. If the credit-risk-related contingent features underlying theseagreements were triggered on March 31, 2009, we would have been requiredto post $2.0 million of collateral with this counterparty. On March 31, 2009,we had no collateral posted with this counterparty.

 

**Note 5—FAS 157 — Fair Value Measurements**

 

FAS 157 establishes athree-tier fair value hierarchy, which prioritizes the inputs used in measuringfair value. These tiers include: (i) Level 1, defined as quoted prices inactive markets for identical instruments; (ii) Level 2, defined as inputsother than quoted prices in active markets that are either directly orindirectly observable; and (iii) Level 3, defined as unobservable inputsin which little or no market data exists, therefore requiring an entity todevelop its own assumptions. Our Level 2 fair value measurements consist ofboth quoted price inputs and inputs provided by a third party that are derivedprincipally from or corroborated by observable market data by correlation. OurLevel 3 fair value measurements consist of both quoted price inputs andunobservable quoted inputs provided by a third party.

 

We consider nonperformancerisk in our evaluation of derivative instruments by analyzing our own creditstanding and the credit standing of our counterparties and considering anycounterparty credit enhancements (e.g. collateral). FAS 157 also requires thatthe fair value measurement of assets and liabilities reflect the nonperformancerisk of counterparties and the reporting entity, as applicable. Therefore,using credit default spreads, we factored the impact of our own credit standingand the credit standing of our counterparties, as well as any potential creditenhancements into the consideration of nonperformance risk for both derivativeassets and liabilities. The results of this analysis were not material to thefinancial statements.

 

The following fair valuehierarchy table presents information about our assets measured at fair valueusing the market value approach on a recurring basis as of March 31, 2009(in thousands):

 

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**March 31, 2009**

 
| ** **                            | ** ** | ** **                                        | ** ** | **Fair Value Measurements Using**                                                    | ** ** |
|---------------------------------------|------------|---------------------------------------------------|------------|-----------------------------------------------------------------------------------------------------|------------|
| **Description**                       | ** ** | **Assets/(Liabilities)  at Fair Value** | ** ** | **Quoted Prices in  Active Markets for  Identical Assets  (Level 1)** | ** ** | **Significant  Other  Observable  Inputs  (Level 2)** | ** ** | **Significant  Unobservable  Inputs  (Level 3)** | ** ** |
| Net derivative  assets/(liabilities)* |       | $                                                 | (9,922     | )                                                                                                   | $          | (11,226 | ) | $ | (2,448 | ) | $ | 3,752 |   |
|                                       |            |                                                   |            |                                                                                                     |            |  |  |  |  |  |  |  |  |

 

**December 31, 2008**

 
| Net derivative  assets/(liabilities)* |   | $ | (6,749 | ) | $ | (14,117 | ) | $ | 1,160 |   | $ | 6,208 |   |
|---------------------------------------|--------|---|--------|---|---|---------|---|---|-------|--------|---|-------|--------|

 

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*Theonly recurring liabilities are derivative related and are netted against theasset amounts shown in the table above.

 

The following tables presentthe net fair value on a recurring basis using significant unobservable inputs (Level3) during the three months ended March 31, 2009 and 2008 (in thousands):

 

**FairValue Measurements Using Significant Unobservable Inputs (Level 3)**

**ThreeMonths Ended March 31, 2009**

 
| **($ in 000’s)**                                              | ** ** | **Net Derivatives(1)** | ** ** | **Total** | ** ** |
|------------------------------------------------------------------------------|------------|-----------------------------|------------|-----------|------------|
| Beginning  Balance, December 31, 2008                                   |       | $                           | 6,208      |      | $          | 6,208 |   |
| Total gains or  (losses) (realized/unrealized)                               |       |                        |       |      |       |
| Included in  earnings (or changes in net assets)                             |       | —                      |       | —    |       |
| Included in  comprehensive income                                            |       | (2,456                      | )          | (2,456    | )          |
| Purchases,  issuances, and settlements                                       |       | —                      |       | —    |       |
| Transfers into  and (out of) Level 3                                         |       | —                      |       | —    |       |
| Ending Balance,  March 31, 2009                                         |       | $                           | 3,752      |      | $          | 3,752 |   |
|                                                                         |       |                        |       |      |       |
| Changes in  unrealized gains relating to assets still held at reporting date |       | $                           | (2,456     | )         | $          | (2,456 | ) |

 

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(1) Netderivatives at March 31, 2009 included derivative assets of $3.8 millionand no derivative liabilities.

 

**ThreeMonths Ended March 31, 2008**

 
| **($ in 000’s)**                                              | ** ** | **Net Derivatives(1)** | ** ** | **Total** | ** ** |
|------------------------------------------------------------------------------|------------|-----------------------------|------------|-----------|------------|
| Beginning  Balance, December 31, 2007                                   |       | $                           | 11,961     |      | $          | 11,961 |   |
| Total gains or  (losses) (realized/unrealized)                               |       |                        |       |      |       |
| Included in  earnings (or changes in net assets)                             |       | —                      |       | —    |       |
| Included in  comprehensive income                                            |       | 305                         |       | 305       |       |
| Purchases,  issuances, and settlements                                       |       | —                      |       | —    |       |
| Transfers into  and (out of) Level 3                                         |       | —                      |       | —    |       |
| Ending Balance,  March 31, 2008                                         |       | $                           | 12,266     |      | $          | 12,266 |   |
|                                                                         |       |                        |       |      |       |
| Changes in  unrealized gains relating to assets still held at reporting date |       | $                           | 305        |      | $          | 305 |   |

 

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(1) Netderivatives at March 31, 2008 included derivative assets of $12.3 millionand no derivative liabilities.

 

**Note 6— Financing**

 

On March 27, 2009, weissued $75 million principal amount of 7% first mortgage bonds due April 1,2024. The net proceeds (after payment of expenses) of approximately $72.7 million were used to repayshort-term debt incurred, in part, to fund our current construction program.

 

On February 25, 2009,we entered into an equity distribution agreement with UBS Securities LLC (UBS).Under the terms of the agreement, we may offer and sell shares of our commonstock, par value $1.00 per share, having an aggregate offering price of up to$60 million from time to time through UBS, as sales agent. We intend to use thenet proceeds from this equity distribution

 

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programto repay short-term debt and for general corporate purposes, including to fundour current construction program. As of April 30, 2009, no shares havebeen sold pursuant to this program.

 

Any sales of the sharespursuant to the equity distribution agreement will be made by means of ordinarybrokers’ transactions on the New York Stock Exchange at market prices or asotherwise agreed with UBS. Under the terms of the program agreement, we mayalso sell shares to UBS as principal for UBS’ own account at a price agreedupon at the time of sale.

 

On March 11, 2009, weentered into a $50 million unsecured credit agreement. This agreement providesfor $50 million of revolving loans to be available to us for working capital,general corporate purposes and to back-up our use of commercial paper andterminates on July 15, 2010. This credit agreement is in addition to, andhas substantially the same covenant requirements and terms as (other thanpricing), our Amended and Restated Unsecured Credit Agreement dated March 14,2006 discussed below. There were no borrowings under this agreement at March 31,2009.

 

On July 15, 2005, weentered into a $150 million unsecured revolving credit facility until July 15,2010. Borrowings (other than through commercial paper) are at the bank’s primecommercial rate or LIBOR plus 100 basis points based on our current creditratings and the pricing schedule in the line of credit facility. On March 14,2006, we entered into the First Amended and Restated Unsecured Credit Agreementwhich amends and restates the $150 million unsecured revolving credit facility.The principal amount of the credit facility was increased to $226 million, withthe additional $76 million allocated to support a letter of credit issued inconnection with our participation in the Plum Point Energy Station project.This extra $76 million of availability reduces over a four year period in linewith the amount of construction expenditures we owe for Plum Point Unit 1 andwas $15.5 million as of May 1, 2009. The unallocated credit facility isused for working capital, general corporate purposes and to back-up our use ofcommercial paper. This facility requires our total indebtedness (which does notinclude our note payable to the securitization trust) to be less than 62.5% ofour total capitalization at the end of each fiscal quarter and our EBITDA(defined as net income plus interest, taxes, depreciation and amortization) tobe at least two times our interest charges (which includes interest on the notepayable to the securitization trust) for the trailing four fiscal quarters atthe end of each fiscal quarter. Failure to maintain these ratios will result inan event of default under the credit facility and will prohibit us fromborrowing funds thereunder. As of March 31, 2009, we are in compliancewith these ratios. This credit facility is also subject to cross-default if wedefault on in****excess of $10 million in the aggregate on ourother indebtedness. This arrangement does not serve to legally restrict the useof our cash in the normal course of operations. There were $38.0 million ofoutstanding borrowings under this agreement at March 31, 2009. Inaddition, $9.25 million of the availability thereunder was used at such date toback up our outstanding commercial paper.

 

**Note 7— Commitments and Contingencies**

 

We are a party to variousclaims and legal proceedings arising out of the normal course of our business.Management regularly analyzes this information, and has provided accruals forany liabilities, in accordance with the guidelines of Statement of FinancialAccounting Standards (SFAS 5), “Accounting for Contingencies” (FAS 5). In theopinion of management, it is not probable, given the company’s defenses, thatthe ultimate outcome of these claims and lawsuits will have a material adverseaffect upon our financial condition, or results of operations or cash flows.

 

**Coal, Natural Gas and Transportation Contracts**

 

We have entered into longand short-term agreements to purchase coal and natural gas for our energysupply and natural gas operations. Under these contracts, the natural gassupplies are divided into firm physical commitments and derivatives that areused to hedge future purchases. In the event that this gas cannot be used, thegas would remain in storage or be liquidated at market price. The firm physicalgas and transportation commitments are as follows (in millions):

 

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Firm physical gas and transportation contracts

 
| April 1,  2009 through March 31, 2010 |   | $    | 37.6   |   |
|-------------------------------------------------|--------|------|--------|--------|
| April 1,  2010 through March 31, 2012 |   | 55.5 |   |
| April 1,  2012 through March 31, 2014 |   | 42.1 |   |
| April 1,  2014 and beyond                  |   | 46.9 |   |

 

We have coal supplyagreements and transportation contracts in place to provide for the delivery ofcoal to the plants. These contracts are written with Force Majeure clauses thatenable us to reduce tonnages or cease shipments under certain circumstances orevents. These include mechanical or electrical maintenance items, acts of God,war or insurrection, strikes, weather and other disrupting events. This reducesthe risk we have for not taking the minimum requirements of fuel under thecontracts. Due to damage incurred in March 2009 to our Asbury rail carunloading facility, we issued Force Majeure notices to our western coalsuppliers and to the railroads, suspending western coal shipments. Thisrelieved us of our contractual obligations to receive shipments of coal untilthe railroad unloading facility is repaired. The minimum requirements for ourcoal and coal transportation contracts are as follows (in millions):

 

Coal and coal transportation contracts

 
| April 1,  2009 through March 31, 2010 |   | $    | 27.4   |   |
|-------------------------------------------------|--------|------|--------|--------|
| April 1,  2010 through March 31, 2012 |   | 22.4 |   |
| April 1,  2012 through March 31, 2013 |   | 8.4  |   |

 

**Purchased Power**

 

We currently supplement ouron-system generating capacity with purchases of capacity and energy from otherutilities in order to meet the demands of our customers and the capacitymargins applicable to us under current pooling agreements and National ElectricReliability Council (NERC) rules.

 

We have contracted withWestar Energy for the purchase of capacity and energy through May 31,2010. Commitments under this contract total approximately $18.9 million throughMay 31, 2010.

 

We also have a long-term (30year) agreement for the purchase of capacity from the Plum Point EnergyStation, a new 665-megawatt, coal-fired generating facility which is beingbuilt by Dynegy near Osceola, Arkansas. Construction began in the spring of2006 and Dynegy reports that substantial completion is scheduled for the summerof 2010. We have the option to purchase an undivided ownership interest in the50 megawatts covered by the purchased power agreement in 2015. Commitmentsunder this contract total approximately $48.0 million through June 30,2015.

 

We have a 20-year purchasedpower agreement with Cloud County Windfarm, LLC, owned by Horizon Wind Energy,Houston, Texas to purchase the energy generated at the approximately105-megawatt Phase 1 Meridian Way Wind Farm located in Cloud County, Kansascommencing with the commercial operation date, which was December 15,2008. We also have a 20-year contract with Elk River Windfarm, LLC, owned byIBERDROLA RENEWABLES, Inc. (formerly known as PPM Energy), to purchase theenergy generated at the 150-megawatt Elk River Windfarm located in ButlerCounty, Kansas. Although these agreements are considered operating leases underGAAP, payments for these wind agreements are recorded as purchased powerexpenses, and, because of the contingent nature of these payments, are notincluded in the operating lease obligations discussed below.

 

**New Construction**

 

On March 14, 2006, weentered into contracts to purchase an undivided interest in 50 megawatts of thePlum Point Energy Station’s new 665-megawatt, coal-fired generating facilitywhich is being built near Osceola, Arkansas. Dynegy reports that substantialcompletion is scheduled for the summer of 2010. The estimated cost isapproximately $88.0 million, excluding

 

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allowancefor funds used during construction (AFUDC). Our share of the Plum Point coststhrough March 31, 2009 was $76.5 million.

 

On June 13, 2006, weannounced we had entered into an agreement with Kansas City Power &Light (KCP&L) to purchase an undivided ownership interest in the coal-firedIatan 2 generating facility. We will own 12%, or approximately 100 megawatts,of the 850-megawatt unit. KCP&L reports that the anticipated in-servicedate for Iatan 2 is the summer of 2010. Our share of the Iatan 2 constructioncosts is expected to be in a range of approximately $218 million to $230million. Our share of the Iatan 2 costs through March 31, 2009 was $147.3million. As a requirement for the air permit for Iatan 2, and to help meetrequirements of the Clean Air Interstate Rule (CAIR), additional emissioncontrol equipment was required for Iatan 1. Our share of the Iatan 1environmental costs through March 31, 2009 was $48.7 million. KCP&Lreported the equipment had met regulatory in-service criteria in April of2009. All of these construction expenditures exclude AFUDC.

 

There are risks that delays beyond our control may materially affectthe schedule, budget and performance of the Iatan and Plum Point projects. Thereare risks that actual costs may exceed budget estimates, delays may occur inobtaining permits and materials, suppliers and contractors may not perform asrequired under their contracts, there may be inadequate availability orproductivity or increased cost of qualified craft labor, start-up activitiesmay take longer than currently planned, the scope and timing of projects maychange, and other events beyond our control, including the failure of one ormore of the generation plant co-owners to pay their share of construction,operations and maintenance costs, may occur that may materially affect theschedule, budget, cost and performance of these projects.

 

**Leases**

 

As discussed above, on June 25,2007, we entered into a 20-year purchased power agreement with Cloud CountyWindfarm, LLC, owned by Horizon Wind Energy, Houston, Texas. Pursuant to theterms of the agreement, we will purchase all of the output from theapproximately 105-megawatt Phase 1 Meridian Way Wind Farm located in CloudCounty, Kansas. We do not own any portion of the windfarm. Annual payments arecontingent upon output of the facility and can range from zero to a maximum ofapproximately $14.6 million based on a 20-year average cost.

 

On December 10, 2004,we entered into a 20-year contract with Elk River Windfarm, LLC to purchase theenergy generated at the 150-megawatt Elk River Windfarm located in ButlerCounty, Kansas. We have contracted to purchase approximately 550,000megawatt-hours of energy per year, or approximately 10% of our annual supplyunder the contract. We do not own any portion of the windfarm. Payments forwind 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.

 

Payments for theseagreements are recorded as purchased power expenses, and, because of thecontingent nature of these payments, are not included in the operating leaseobligations shown below.

 

Wealso currently have short-term operating leases for two unit trains to meetcoal delivery demands, for garage and office facilities for our electricsegment and for six service center properties for our gas segment. In additionwe have a five-year capital lease for telephone equipment.

 

Ourlease obligations over the next five years have not significantly changed at March 31,2009, compared to December 31, 2008.

 

**Environmental Matters**

 

We are subject to variousfederal, state, and local laws and regulations with respect to air and waterquality and with respect to hazardous and toxic materials and wastes, includingtheir identification, transportation, disposal, record-keeping and reporting,as well as other environmental matters. We believe that our operations are incompliance with present laws and regulations.

 

***Electric Segment***

 

*Air.* The 1990 Amendments to the Clean Air Act, referredto as the 1990 Amendments, affect the Asbury, Riverton, State Line and Iatan 1Power 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 the 1990 Amendments, the amount of SO2an affected unit can emit is regulated. Each existing affected unit has beenallocated a specific number of emission allowances, each of which allows theholder to emit one ton of SO2. Utilities covered by the 1990 Amendments musthave emission allowances equal to the number of tons of SO2 emitted during agiven year by each of their affected units. The annual reconciliation ofallowances, which occurs on a facility wide basis, is held each March 1for the previous calendar year. Allowances may be traded between plants****or utilities or “banked” for future use. A market for thetrading of emission allowances exists on the Chicago Board of Trade. TheEnvironmental****Protection Agency****(EPA) withholdsannually a percentage of the emission allowances allocated to each affectedunit and sells those emission allowances through a direct auction. We receivecompensation from the EPA for the sale of these withheld allowances. During2008, we received less than $0.1 million from the EPA auction.

 

Our Asbury, Riverton andIatan coal plants collectively receive 11,723 allowances per year. They burn ablend of low sulfur Western coal (Powder River Basin) and higher sulfur blendcoal and petroleum coke, or burn 100% low sulfur Western coal. In addition,tire-derived fuel (TDF) is used as a supplemental fuel at the Asbury Plant. TheRiverton Plant can also burn natural gas as its primary fuel. The State LinePlant, the Energy Center Units 3 and 4 and Riverton Unit 12 are gas-firedfacilities and are allocated zero SO2 allowances. In the near term, annualallowance requirements for the State Line Plant, the Energy Center Units 3 and4 and Riverton Unit 12, which are not expected to exceed 20 allowances peryear, will be transferred from our inventoried bank of allowances. In 2008, thecombined actual SO2 allowance need for all affected plant facilities exceededthe number of allowances allocated to us by the EPA. As of March 1, 2009,we had 17,394 banked SO2 allowances as compared to 23,800 at March 1,2008. We project that our 2009 emissions will again exceed the number ofallowances allocated by the EPA by an amount approximately equal to thedifference during 2008.

 

When our SO2 allowance bankis exhausted, currently estimated to be mid-2011, we will need to purchaseadditional SO2 allowances or build a Flue Gas Desulphurization (FGD) scrubbersystem at our Asbury Plant. Based on current and projected SO2 allowance pricesand high-level estimated FGD scrubber construction costs ($81 million in 2010 dollars),we project it will be more economical for us to purchase SO2 allowances than tobuild a scrubber at the Asbury Plant. Based on SO2 allowance market prices asof May 4, 2009 in conjunction with currently estimated future operatingparameters at the Asbury Plant, we estimate it will cost us approximately $0.4million to purchase SO2 allowances for the remainder of 2011 and a range ofapproximately $0.45 million to $0.75 million annually for the years 2012through 2018. We would expect the costs of SO2 allowances to be fullyrecoverable in our rates.

 

Effective 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 exchange banked allowances forfuture vintage allowances and/or monetary value and, in extreme marketconditions, to sell SO2 allowances outright for monetary value. We have not yetexchanged or sold any allowances under the SAMP.

 

SO2 emissions will befurther regulated as described in the Clean Air Interstate Rule sectionbelow.

 

NOxEmissions. TheAsbury, Iatan, State Line, Energy Center and Riverton Plants are each incompliance with the NOx limits applicable to them under the 1990 Amendments ascurrently operated.

 

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

 

Under the MDNR’s MissouriNOx Rule, our Iatan, Asbury, State Line and Energy Center facilities, likeother facilities in western Missouri, are generally subject to a maximum NOxemission rate of 0.35 lbs/MMBtu during the ozone season of May 1 through September 30.Facilities which burn at least 100,000 passenger tire equivalents of TDF peryear, including our Asbury Plant, are

 

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subjectto a higher NOx emission limit of 0.68 lbs/MMBtu. All of our plants currentlymeet the required emission limits.

 

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 several counties in southwest Missouri will be classified as beingin non-attainment of the ozone NAAQS standard by the EPA in 2010 or later. Weanticipate that the EPA will classify the Kansas City area, where Iatan 1 islocated, as being in non-attainment in 2010. At this time we do not foresee theneed for additional pollution controls due to the reduction in the ozonestandard. In addition, our units do not emit appreciable VOCs. We do notanticipate that southeast Kansas, where our Riverton Plant is located, will beclassified as non-attainment under the new ozone NAAQS.

 

NOx emissions are furtherregulated as described in the Clean Air Interstate Rule section below.

 

Clean Air Interstate Rule (CAIR)

 

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

 

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

 

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 finalized their respectiveregulations and submitted their SIPs to the EPA, which were approved. We havereceived our full allotment of allowances as published in the Missouri CAIRRule. Under the Arkansas CAIR rule, we will not receive allowances untilapproximately six years after Plum Point Unit 1 is operational. In the interim,we will transfer allowances from our Missouri units. Based on SIPs for Missouriand Arkansas, we believe we will have excess annual and ozone season NOxallowances. SO2 allowances must be utilized at a 2:1 ratio for our Missouriunits as compared to our non-CAIR Kansas units beginning in 2010. As a result,based on current SO2 allowance usage projections, we expect to exhaust ourbanked allowances by mid-2011 and will need to purchase additional SO2allowances or build a scrubber at our Asbury Plant.

 

In order to meet CAIR requirements for Iatan 1and to meet air permit requirements for Iatan 2, pollution control equipmenthas been installed on Iatan 1. Installation was completed in the first quarterof 2009 and KCP&L reported the equipment met in-service criteria in April of2009. This equipment includes a Selective Catalytic Reduction (SCR) system, anFGD scrubber and a baghouse, with our share of the capital cost estimated to bebetween $58 million and $60 million, excluding AFUDC. Of this amount,approximately $3.9 million was incurred in 2006, $12.1 million in 2007 and$27.3 million in 2008 with estimated expenditures of approximately $15.6million in 2009. This project was also included as part of our ExperimentalRegulatory Plan approved by the MPSC.

 

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

 

AirPermits.**Under Title V of the 1990 Amendments, we must obtain siteoperating permits for each of our plants from the authorities in the state inwhich the plant is located. These permits, which are 

 

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validfor five years, regulate the plant site’s total air emissions; includingemissions from stacks, individual pieces of equipment, road dust, coal dust andother emissions. We have been issued permits for Asbury, Iatan, Riverton, StateLine and the Energy Center Plants. We submitted the required renewalapplications for the State Line and Energy Center Title V permits in 2003 andthe Asbury Title V permit in 2004 and will operate under the existing permitsuntil the Missouri Department of Natural Resources (MDNR) issues the renewedpermits. A Compliance Assurance Monitoring (CAM) plan for particulate matter(PM) will be required by the renewed permit for Asbury. We estimate that thecapital costs associated with the PM CAM plan will not exceed $2 million. Wesubmitted the renewal application for the Riverton Title V permit in June 2008.A CAM plan for PM will also be required by the renewed permit for Riverton. Noadditional capital costs are anticipated. It is expected that the KansasDepartment of Health and Environment (KDHE) will issue the renewal permit forRiverton in the second quarter of 2009.

 

A new air permit was issuedfor the Iatan Generating Station on January 31, 2006. The new permitcovers the entire Iatan Generating Station and includes the existing Unit No. 1and Iatan Unit No. 2 currently under construction. The new permit limitsUnit No. 1 to a maximum of 6,600 MMBtu per hour of heat input. The 6,600MMBtu per hour heat input limit is in effect until the new SCR, scrubber, andbaghouse are in place and fully operational.

 

The Clean Air Act requiredcompanies to obtain permits and, if necessary, install control equipment toreduce emissions when making a major modification or a change in operation ifeither is expected to cause a significant net increase in regulated emissions.The Sierra Club and Concerned Citizens of Platte County have claimed thatmodifications were made to Iatan 1 prior to the Comprehensive Energy Planproject in violation of Clean Air Act regulations. We own 12% of Iatan 1. Asoperator, KCP&L entered into a Collaboration Agreement with those partiesthat provide, among other things, for the release of such claims. In May 2008,a grand jury subpoena requesting documents was received by KCP&L. KCP&Lhas provided documentation in response to the subpoena. The outcome of theseactivities cannot presently be determined, nor can the costs and otherliabilities that could potentially result from a negative outcome presently bereasonably estimated.

 

CleanAir Mercury Rule (CAMR)

 

On March 15, 2005, theEPA issued the CAMR regulations for mercury emissions by power plants under therequirements of the 1990 Amendments to the Clean Air Act. The new mercuryemission limits of CAMR Phase 1 were to go into effect January 1, 2010. OnFebruary 8, 2008, the U.S. Court of Appeals for the District of Columbiavacated the EPA’s CAMR regulations which was appealed to the U.S. Supreme Courton October 17, 2008. On February 23, 2009, the U.S. Supreme Courtdenied the appeal.

 

The EPA has not issuedguidance to the states regarding the vacated regulation nor recommended futureactions. Based on CAMR, we installed a mercury analyzer at Asbury during late2007 and installed two mercury analyzers at Riverton in 2008 in order to verifyour mercury emissions and to meet the monitoring compliance date of January 1,2009 and the Phase 1 mercury emission compliance date of January 1, 2010.We will operate the mercury analyzers at Riverton and Asbury in accordance withthe appropriate state environmental regulator’s guidance.

 

The CAMR rulemaking wasrevoked by the EPA after final adjudication. Maximum Achievable ControlTechnology (MACT) re-emerged under current law but no specific MACT rulemakingshave yet been adopted in Missouri or Kansas.

 

CO2 Emissions

 

Ourcoal and gas plants emit carbon dioxide (CO2), a greenhouse gas (GHG). Althoughnot currently regulated, increasing public concern and political pressure fromlocal, regional, national and international bodies is likely to result in thepassage of new laws mandating limits on GHG emissions such as CO2. The EPArecently proposed a mandatory GHG reporting system to become effective in early2011 applicable to power generating and certain other facilities that exceedspecified emission thresholds. Also, in response to a 2007 decision of the U.S. Supreme Court

 

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determiningthat GHG are air pollutants under the CAA, on April 17, 2009 the EPA proposeda finding that GHG, including CO2, threaten the public health and welfare. Iffinally adopted, this endangerment finding by the EPA may lead it to promulgateregulations for GHG emissions, including those from power plants. The U.S. Congress is actively consideringvarious options including a cap and trade system, also a stated priority of theObama Administration, which would impose a limit and price on GHG emissions andestablish a market for trading GHG credits. Certain states have taken steps todevelop similar systems which may be more stringent than any federalregulations. For example, Kansas is a participating member of the MidwesternGreenhouse Gas Reduction Accord, one purpose of which is to develop amarket-based cap and trade mechanism to reduce GHG emissions. The impact on usof any future GHG regulation will depend in large part on the details of therequirements and the timetable for mandatory compliance. We would expect thecost of complying with any such regulations to be fully recoverable in ourrates.

 

*Water.* We operate under the Kansas and MissouriWater Pollution 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 Riverton Plant is affectedby final regulations for Cooling Water Intake Structures issued under the CleanWater Act (CWA) Section 316(b) Phase II. The regulations became finalon February 16, 2004 and required the submission of a Sampling Report andComprehensive Demonstration Study with the permit renewal in 2008. Sampling andsummary reports, which were completed during the first quarter of 2008 andsubmitted to the KDHE, indicate that the effect of the cooling water intakestructure on Empire Lake’s aquatic life is insignificant. The need for afurther Demonstration Study is not expected. On January 25, 2007, theUnited States Court of Appeals for the Second Circuit remanded key sections ofthese CWA regulations. On July 9,2007, the EPA suspended the regulation and is expected to revise and re-proposethe regulation in 2009. 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. On April 1, 2009, the U.S. Supreme Courtoverturned the lower court’s ruling on the cost/benefit issue and remanded theregulation to the EPA. The permit renewal application was prepared andsubmitted in June 2008 and the final permit was received on January 1,2009. Under the initial regulations, we did not expect costs associated withcompliance to be material. We will reassess costs after the revised rules arecomplete.

 

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

 

*Renewable Energy.*On November 4, 2008, Missouri votersapproved the Clean Energy Initiative (Proposition C). This initiative requiresinvestor-owned utilities in Missouri (such as Empire) to generate or purchaseelectricity from renewable energy sources, such as solar, wind, biomass andhydro power, at the rate of at least 2% in retail sales by 2011, increasing toat least 15% by 2021. At least 25 other states have adopted renewable portfoliostandard (RPS) programs that mandate some form of renewable generation. Some ofthese RPS programs incorporate a trading system in which utilities are allowedto buy and sell renewable energy certificates (RECs) in order to meetcompliance. Additionally, RECs are utilized by many companies in “green”marketing efforts. REC prices are driven by various market forces. We have beenselling RECs and plan to continue to sell all or a portion of the RECsassociated with our contracts with Elk River Windfarm, LLC and Cloud County Windfarm,LLC. With respect to the energy underlying the RECs that we sell, we may notclaim that we are purchasing renewable energy****for any purpose, including for purposes ofcomplying with the new Missouri requirements. Over time, we expect to retainsome of the renewable attributes associated with these contracts in order tomeet the new Missouri requirements. We realized revenues of $1.8 million fromREC sales in 2008 and $0.9 million in 2007.

 

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The MPSC initiated aproceeding on March 9, 2009 to develop a rulemaking to implementProposition C. The proceeding includes workshops and public comment periods toallow for input from industry as well as the public at large. We expect thisprocess to conclude in 2009.

 

***Gas Segment***

 

Theacquisition of Missouri Gas involved the property transfer of two formermanufactured gas plant (MGP) sites previously owned by Aquila, Inc. andits predecessors. Site #1 in Chillicothe, Missouri is listed in the MDNRRegistry of Confirmed Abandoned or Uncontrolled Hazardous Waste Disposal Sitesin Missouri. Site #2 in Marshall, Missouri has received a letter of no furtheraction from the MDNR. A Change of Use request and work plan was approved by theMDNR allowing us to expand our existing service center at Site #1 inChillicothe, Missouri. This project, which was completed in October 2007,included the removal of all excavated soil and the addition of a new concretesurface replacing the existing gravel at a cost of approximately $0.1 million.We estimate further remediation costs at these two sites to be no more thanapproximately $0.2 million, based on our best estimate at this time. Theremaining liability balance of $0.2 million is recorded under noncurrentliabilities and deferred credits. In our agreement with the MPSC approving theacquisition of Missouri Gas, it was agreed that we could reflect a liabilityand offsetting regulatory asset not to exceed $260,000 for the acquired sites.The MPSC agreed that up to $260,000 of costs related to the clean up of theseMGP sites would be allowed for future rate recovery. Accordingly, we concludedthat rate recovery was probable and at the acquisition date, a regulatory assetof $260,000 was recorded as part of the purchase price allocation based on ouragreement with the MPSC, and in accordance with SFAS 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 and is shown for our noncontributorydefined benefit pension plan, our supplemental retirement program (SERP) andother postretirement benefits (OPEB) (in thousands):

 
| ** **                              | ** ** | **Three months ended March 31,** | ** ** |
|-----------------------------------------|------------|------------------------------------------------------|------------|
| ** **                              | ** ** | **Pension**                                          | ** ** | **SERP** | ** ** | **OPEB** | ** ** |
| ** **                              | ** ** | **2009**                                             | ** ** | **2008** | ** ** | **2009** | ** ** | **2008** | ** ** | **2009** | ** ** | **2008** | ** ** |
| Service cost                            |       | $                                                    | 991        |   | $ | 863 |   | $ | 16 |   | $ | 12 |   | $ | 454 |   | $ | 407 |   |
| Interest cost                           |       | 2,437                                                |       | 2,245 |   | 36 |   | 32 |   | 986 |   | 910 |   |
| Expected return  on plan assets         |       | (2,601                                               | )          | (2,680 | ) |   |   |   |   | (960 | ) | (938 | ) |
| Amortization of  prior service cost (1) |       | 151                                                  |       | 186 |   | (2 | ) | (2 | ) | (253 | ) | (253 | ) |
| Amortization of  net actuarial loss (1) |       | 754                                                  |       | 404 |   | 32 |   | 30 |   | 232 |   | 140 |   |
| **Net  periodic benefit cost**          | ** ** | **$**                                                | **1,732**  | ** ** | **$** | **1,018** | ** ** | **$** | **82** | ** ** | **$** | **72** | ** ** | **$** | **459** | ** ** | **$** | **266** | ** ** |

 
| ** **                              | ** ** | **Twelve months ended March 31,** | ** ** |
|-----------------------------------------|------------|-------------------------------------------------------|------------|
| ** **                              | ** ** | **Pension**                                           | ** ** | **SERP** | ** ** | **OPEB** | ** ** |
| ** **                              | ** ** | **2009**                                              | ** ** | **2008** | ** ** | **2009** | ** ** | **2008** | ** ** | **2009** | ** ** | **2008** | ** ** |
| Service cost                            |       | $                                                     | 3,697      |   | $ | 3,480 |   | $ | 61 |   | $ | 50 |   | $ | 1,698 |   | $ | 1,586 |   |
| Interest cost                           |       | 9,240                                                 |       | 8,439 |   | 142 |   | 119 |   | 3,692 |   | 3,352 |   |
| Expected return  on plan assets         |       | (10,651                                               | )          | (10,392 | ) |   |   |   |   | (3,772 | ) | (3,511 | ) |
| Amortization of  prior service cost (1) |       | 709                                                   |       | 680 |   | (8 | ) | (10 | ) | (1,011 | ) | (1,138 | ) |
| Amortization of  net actuarial loss (1) |       | 2,043                                                 |       | 2,355 |   | 133 |   | 140 |   | 604 |   | 991 |   |
| **Net  periodic benefit cost**          | ** ** | **$**                                                 | **5,038**  | ** ** | **$** | **4,562** | ** ** | **$** | **328** | ** ** | **$** | **299** | ** ** | **$** | **1,211** | ** ** | **$** | **1,280** | ** ** |

 

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(1) Amountsare amortized from our regulatory asset originally recorded upon adoption ofFAS 158.

 

Based on the performance of our pension plan assets through January 1,2008 and 2009, we were not required by law to fund any additional minimumamounts with respect to 2008.

 

The expected minimum fundingfor 2009 is estimated to be between $0.0 million and $4.0 million.  For 2010, it is estimated to be between $9.0million and $15.0 million.  The actualminimum 

 

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funding requirements will bedetermined based on the results of the actuarial valuations and, in the case of2010, the performance of our pension assets during 2009.

 

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

 

As of September 30,2008, our performance based restricted stock awards, stock options and theirrelated dividend equivalents are classified as liability awards, in accordancewith fair value guidelines. We allow employees to elect to have taxes in excessof the minimum statutory requirements withheld from their awards and,therefore, the awards are classified as liability instruments under FAS 123(R) “ShareBased Payment” (paragraph 35). Awards treated as liability instruments must berevalued each period until settled, and cost is accrued over the requisiteservice period and adjusted to fair value at each reporting period untilsettlement or expiration of the award.

 

We recognized the followingamounts in compensation expense and tax benefits for all of our stock-basedawards and programs for the applicable periods ended March 31 (inthousands):

 
| ** **                  | ** ** | **Three Months Ended** | ** ** | **Twelve Months Ended** | ** ** |
|-----------------------------|------------|----------------------------------|------------|-----------------------------------|------------|
| ** **                  | ** ** | **2009**                         | ** ** | **2008**                          | ** ** | **2009** | ** ** | **2008** | ** ** |
| ** **                  |       |                             |       |                              |       |   |   |   |   |
| **Compensation  expense**   |       | $                                | 580        |                              | $          | 875 |   | $ | 1,546 |   | $ | 2,243 |   |
| **Tax  benefit recognized** |       | 209                              |       | 324                               |       | 544 |   | 818 |   |
|                             |            |                                  |            |                                   |            |  |  |  |  |  |  |  |  |

 

Activityfor our various stock plans for the three months ended March 31, 2009, issummarized below:

 

**Performance-BasedRestricted Stock Awards**

 

As noted above, allperformance-based restricted stock awards are classified as liabilityinstruments, which must be revalued each period until settled. The fair valueof the outstanding restricted stock awards was estimated as of March 31,2009 and 2008 using a Monte Carlo option valuation model. The 2009 valuationrepresents the estimated March 31, 2009 fair value for all awards grantedin previous years, but not yet awarded. The 2008 grant value reflects theassumptions used for the fair value as of the grant date for awardsoutstanding. The assumptions used in the model for each grant year are noted inthe following table:

 
| ** **                               | ** ** | **Fair Value of Grants Outstanding at March 31,** | ** ** |
|------------------------------------------|------------|--------------------------------------------------------------------------------------|------------|
| ** **                               | ** ** | **2009**                                                                             | ** ** | **2008** | ** ** |
| Risk-free  interest rate                 |       | 0.50% to 1.08%                                                                       |       | 2.44% to 5.09% |   |
| Expected  volatility of Empire stock     |       | 28.5%                                                                                |       | 15.2% to 19.9% |   |
| Expected  volatility of peer group stock |       | 21.6% to 75.5%                                                                       |       | 14.1% to 34.6% |   |
| Expected  dividend yield on Empire stock |       | 6.8%                                                                                 |       | 5.4% to 5.8% |   |
| Expected  forfeiture rates               |       | 3%                                                                                   |       | 3% |   |
| Plan cycle                               |       | 3 years                                                                              |       | 3 years |   |
| Fair value  percentage                   |       | 91.0% to 102.0%                                                                      |       | 107.73% to 113.0% |   |
| Weighted average  fair value per share   |       | $ 15.08                                                                         |       | $ 24.88 |   |

 

Non-vested restricted stock awards (based on targetnumber) as of March 31, 2009 and 2008 and changes during the three monthsended March 31, 2009 and 2008 were as follows:

 

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| ** **                        | ** ** | **2009**                   | ** ** | **2008**                                              | ** ** |
|-----------------------------------|------------|----------------------------|------------|-------------------------------------------------------|------------|
| ** **                        | ** ** | **Number  of shares** | ** ** | **Weighted Average  Grant Date Price** | ** ** | **Number  of shares** | ** ** | **Weighted Average  Grant Date Price** | ** ** |
|                              |       |                       |       |                                                  |       |   |   |   |   |
| **Nonvested  at January 1,** |       | 52,300                     |       | $                                                     | 22.64      |   | 43,400 |   | $ | 23.02 |   |
| **Granted**                       |       | 13,500                     |       | $                                                     | 18.12      |   | 21,000 |   | $ | 21.92 |   |
| **Awarded**                       |       | (12,394                    | )          | $                                                     | 22.23      |   | (6,486 | ) | $ | 22.77 |   |
| **Not  Awarded**                  |       | (1,206                     | )          | —                                                |       | (5,614 | ) | — |   |
|                              |       |                       |       |                                                  |       |   |   |   |   |
| **Nonvested  at March 31,**  |       | 52,200                     |       | $                                                     | 21.57      |   | 52,300 |   | $ | 22.64 |   |

 

At March 31, 2009,there was $0.4 million of total unrecognized compensation cost related toestimated outstanding awards. This cost will be recognized over the remainingvesting period.

 

**StockOptions**

 

Asnoted above, all outstanding stock option awards are classified as liability instrumentsas of September 30, 2008, and are revalued each period until settled.Stock option grants vest upon satisfaction of service conditions. The cost ofthe awards is generally recognized over the requisite (explicit) serviceperiod. The fair value of the outstanding options was estimated as of March 31,2009 and 2008, under a Black-Scholes methodology. The 2009 valuation representsthe estimated fair value for all awards granted in previous years, outstandingat March 31, 2009. The 2008 grant value reflects the assumptions used forthe fair value as of the grant date for options outstanding. The assumptionsused in the valuations are shown below:

 
| ** **                                  | ** ** | **Fair Value of Grants Outstanding at March 31,** | ** ** |
|---------------------------------------------|------------|--------------------------------------------------------------------------------------|------------|
| ** **                                  | ** ** | **2009**                                                                             | ** ** | **2008** | ** ** |
| **Risk-free  interest rate**                |       | 0.99% to 2.08%                                                                       |       | 3.27% to 4.68% |   |
| **Dividend  yield**                         |       | 6.8%                                                                                 |       | 5.33% to 6.16% |   |
| **Expected  volatility**                    |       | 24.0%                                                                                |       | 16.13% to 20.0% |   |
| **Expected  life in months**                |       | 78                                                                                   |       | 60 to 78 |   |
| **Market  value**                           |       | $14.44                                                                               |       | $20.25 |   |
| **Weighted  average fair value per option** |       | $ 0.35                                                                          |       | $ 2.21 |   |

 

Asummary of option activity under the plan during the three months ended March 31,2009 and 2008 is presented below:

 
| ** **                      | ** ** | **2009**    | ** ** | **2008**              | ** ** |
|---------------------------------|------------|-------------|------------|-----------------------|------------|
| ** **                      | ** ** | ** **  | ** ** | **Weighted  Average** | ** ** | ** ** | ** ** | **Weighted  Average** | ** ** |
| ** **                      | ** ** | ** **  | ** ** | **Exercise**          | ** ** | ** ** | ** ** | **Exercise** | ** ** |
| ** **                      | ** ** | **Options** | ** ** | **Price**             | ** ** | **Options** | ** ** | **Price** | ** ** |
| Outstanding at  January 1, |       | 205,600     |       | $                     | 22.73      |   | 149,200 |   | $ | 23.04 |   |
| Granted                         |       | 27,000      |       | $                     | 18.12      |   | 56,400 |   | $ | 21.92 |   |
| Exercised                       |       | —      |       | —                |       | — |   | — |   |
| Outstanding at  March 31,  |       | 232,600     |       | $                     | 22.19      |   | 205,600 |   | $ | 22.73 |   |
| Exercisable at  March 31,  |       | 85,000      |       | $                     | 22.46      |   | 43,300 |   | $ | 22.67 |   |

 

Theaggregate intrinsic value at March 31, 2009 and 2008 was zero. Theintrinsic value of the unexercised options is the difference between Empire’sclosing stock price on the last day of the quarter and the exercise pricemultiplied by the number of in the money options had all option holdersexercised their option on the last day of the quarter. The intrinsic value iszero if such closing price is less than the exercise price.

 

Therange of exercise prices for the options outstanding at March 31, 2009 was$18.12 to $23.81. The weighted-average remaining contractual life ofoutstanding options at March 31, 2009 

 

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and2008 was 7.3 years and 7.8 years, respectively. As of March 31, 2009,there was $0.3 million of total unrecognized compensation expense related tothe non-vested options and related dividend equivalents granted under the plan.That cost will be recognized over a period of 1 to 3 years.

 

**Note 10 - Regulated Operating Expense**

 

The following table sets forth the major components comprising “regulatedoperating expenses” under “Operating Revenue Deductions” on our consolidatedstatements of operations (in thousands) for all periods presented ended March 31:

 
| ** **                                         | ** ** | **Three Months  Ended** | ** ** | **Three Months  Ended** | ** ** | **Twelve Months  Ended** | ** ** | **Twelve Months  Ended** | ** ** |
|----------------------------------------------------|------------|------------------------------|------------|------------------------------|------------|-------------------------------|------------|-------------------------------|------------|
| ** **                                         | ** ** | **2009**                     | ** ** | **2008**                     | ** ** | **2009**                      | ** ** | **2008**                      | ** ** |
| Electric  transmission and distribution expense    |       | $                            | 2,590      |                         | $          | 2,657                         |       | $                             | 10,824     |   | $ | 10,059 |   |
| Natural gas  transmission and distribution expense |       | 526                          |       | 474                          |       | 2,047                         |       | 1,786                         |       |
| Power operation  expense (other than fuel)         |       | 3,064                        |       | 2,713                        |       | 12,022                        |       | 10,770                        |       |
| Customer  accounts and assistance expense          |       | 2,451                        |       | 2,548                        |       | 10,069                        |       | 9,628                         |       |
| Employee pension  expense (1)                      |       | 1,360                        |       | 1,554                        |       | 5,698                         |       | 6,290                         |       |
| Employee  healthcare plan (1)                      |       | 1,317                        |       | 1,943                        |       | 6,510                         |       | 8,065                         |       |
| General office  supplies and expense               |       | 2,260                        |       | 2,442                        |       | 9,148                         |       | 10,170                        |       |
| Administrative  and general expense                |       | 2,999                        |       | 2,958                        |       | 11,768                        |       | 11,002                        |       |
| Allowance for  uncollectible accounts              |       | 947                          |       | 572                          |       | 3,320                         |       | 3,890                         |       |
| Miscellaneous  expense                             |       | (12                          | )          | 37                           |       | 116                           |       | 242                           |       |
| Total                                              |       | $                            | 17,502     |                         | $          | 17,898                        |       | $                             | 71,522     |   | $ | 71,902 |   |

 

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(1) Does not include capitalized portion of costs, but reflects theGAAP expensed cost plus or minus costs deferred to a regulatory asset orrecognized as a regulatory liability for Missouri and Kansas jurisdictions.

 

**Note 11—Segment Information**

 

We operate our business as three segments:  electric, gas and other. As part of ourelectric segment, we also provide water service to three towns in Missouri. Theother segment consists of our non-regulated businesses, primarily a subsidiaryfor our fiber optics business.

 

The tables below present statement of operations information, balancesheet information and capital expenditures of our business segments.

 
| ** **                               | ** ** | **For the quarter ended March 31,** | ** ** |
|------------------------------------------|------------|--------------------------------------------------------------|------------|
| ** **                               | ** ** | **2009**                                                     | ** ** |
| **($-000’s)**                       | ** ** | **Electric**                                                 | ** ** | **Gas** | ** ** | **Other** | ** ** | **Eliminations** | ** ** | **Total** | ** ** |
| ** **                               |       |                                                         |       |   |   |   |   |   |   |   |   |
| **Statement  of Operations Information** |       |                                                         |       |   |   |   |   |   |   |   |   |
| Revenues                                 |       | $                                                            | 106,787    |   | $ | 28,087 |   | $ | 1,302 |   | $ | (161 | ) | $ | 136,015 |   |
| Depreciation and  amortization           |       | 11,829                                                       |       | 501 |   | 343 |   | — |   | 12,673 |   |
| Federal and  state income taxes          |       | 4,370                                                        |       | 1,044 |   | 195 |   | — |   | 5,609 |   |
| Operating income                         |       | 15,698                                                       |       | 2,614 |   | 343 |   | — |   | 18,655 |   |
| Interest income                          |       | 75                                                           |       | 159 |   | — |   | (157 | ) | 77 |   |
| Interest expense                         |       | 10,559                                                       |       | 996 |   | 26 |   | (157 | ) | 11,424 |   |
| Income from  AFUDC (debt and equity)     |       | 3,602                                                        |       | 1 |   | — |   | — |   | 3,603 |   |
| Net income                               |       | 8,843                                                        |       | 1,753 |   | 317 |   | — |   | 10,913 |   |
|                                     |       |                                                         |       |   |   |   |   |   |   |   |   |
| **Capital  Expenditures**                |       | $                                                            | 42,808     |   | $ | 471 |   | $ | 545 |   | $ | — |   | $ | 43,824 |   |

 

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| ** **                               | ** ** | **For the quarter ended March 31,** | ** ** |
|------------------------------------------|------------|--------------------------------------------------------------|------------|
| ** **                               | ** ** | **2008**                                                     | ** ** |
| **($-000’s)**                       | ** ** | **Electric**                                                 | ** ** | **Gas** | ** ** | **Other** | ** ** | **Eliminations** | ** ** | **Total** | ** ** |
|                                     |       |                                                         |       |   |   |   |   |   |   |   |   |
| **Statement  of Operations 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 |   |
| Net income                               |       | 4,359                                                        |       | 2,455 |   | 176 |   | — |   | 6,990 |   |
|                                     |       |                                                         |       |   |   |   |   |   |   |   |   |
| **Capital  Expenditures**                |       | $                                                            | 54,248     |   | $ | 436 |   | $ | 415 |   | $ | — |   | $ | 55,099 |   |

 
| ** **                               | ** ** | **For the twelve months ended March 31,** | ** ** |
|------------------------------------------|------------|-------------------------------------------------------------------------|------------|
| ** **                               | ** ** | **2009**                                                                | ** ** |
| **($-000’s)**                       | ** ** | **Electric**                                                            | ** ** | **Gas** | ** ** | **Other** | ** ** | **Eliminations** | ** ** | **Total** | ** ** |
|                                     |       |                                                                    |       |   |   |   |   |   |   |   |   |
| **Statement  of Operations Information** |       |                                                                    |       |   |   |   |   |   |   |   |   |
| Revenues                                 |       | $                                                                       | 446,294    |   | $ | 66,250 |   | $ | 5,245 |   | $ | (557 | ) | $ | 517,232 |   |
| Depreciation and  amortization           |       | 49,315                                                                  |       | 1,961 |   | 1,337 |   | — |   | 52,613 |   |
| Federal and  state income taxes          |       | 20,646                                                                  |       | 521 |   | 462 |   | — |   | 21,629 |   |
| Operating income                         |       | 69,178                                                                  |       | 4,656 |   | 1,274 |   | — |   | 75,108 |   |
| Interest income                          |       | 1,134                                                                   |       | 434 |   | — |   | (513 | ) | 1,055 |   |
| Interest expense                         |       | 41,207                                                                  |       | 3,968 |   | 169 |   | (513 | ) | 44,831 |   |
| Income from  AFUDC (debt and equity)     |       | 13,644                                                                  |       | 10 |   | — |   | — |   | 13,654 |   |
| Net income                               |       | 41,921                                                                  |       | 975 |   | 750 |   | — |   | 43,646 |   |
|                                     |       |                                                                    |       |   |   |   |   |   |   |   |   |
| **Capital  Expenditures**                |       | $                                                                       | 200,467    |   | $ | 2,183 |   | $ | 2,082 |   | $ | — |   | $ | 204,732 |   |

 
| ** **                               | ** ** | **For the twelve months ended March 31,** | ** ** |
|------------------------------------------|------------|-------------------------------------------------------------------------|------------|
| ** **                               | ** ** | **2008**                                                                | ** ** |
| **($-000’s)**                       | ** ** | **Electric**                                                            | ** ** | **Gas** | ** ** | **Other** | ** ** | **Eliminations** | ** ** | **Total** | ** ** |
|                                     |       |                                                                    |       |   |   |   |   |   |   |   |   |
| **Statement  of Operations 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 |   |

 

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**As of March 31, 2009**

 
| **($-000’s)**             | ** ** | **Electric** | ** ** | **Gas(1)** | ** ** | **Other** | ** ** | **Eliminations** | ** ** | **Total** | ** ** |
|--------------------------------|------------|--------------|------------|------------|------------|-----------|------------|------------------|------------|-----------|------------|
| **Balance  Sheet Information** |       |         |       |       |       |      |       |             |       |      |       |
| Total assets                   |       | $            | 1,646,585  |       | $          | 136,970   |       | $                | 22,399     |      | $          | (81,129 | ) | $ | 1,724,825 |   |
|                                |            |              |            |            |            |           |            |                  |            |           |            |  |  |  |  |  |

 

----

(1) Includes goodwill of $39,492.

 

**As of December 31, 2008**

 
| **($-000’s)**             | ** ** | **Electric** | ** ** | **Gas(1)** | ** ** | **Other** | ** ** | **Eliminations** | ** ** | **Total** | ** ** |
|--------------------------------|------------|--------------|------------|------------|------------|-----------|------------|------------------|------------|-----------|------------|
| **Balance  Sheet Information** |       |         |       |       |       |      |       |             |       |      |       |
| Total assets                   |       | $            | 1,621,502  |       | $          | 138,788   |       | $                | 22,186     |      | $          | (68,630 | ) | $ | 1,713,846 |   |
|                                |            |              |            |            |            |           |            |                  |            |           |            |  |  |  |  |  |

 

----

(1) Includesgoodwill of $39,492.

 

**Note 12—Discontinued Operations**

 

On September 28, 2007, we sold our 100%interest in Fast Freedom, Inc., an Internet service provider. We havereported Fast Freedom’s results as discontinued operations. A summary of thecomponents of gains or losses from discontinued operations for the affectedperiod follows:

 

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

 
| **($-000’s)**                                       | ** ** | ** ** | ** ** |
|----------------------------------------------------------|------------|------------|------------|
| Revenues                                                 |       | $          | 593        |   |
| Expenses                                                 |       | 701        |       |
| Losses from  discontinued operations before income taxes |       | (108       | )          |
| Gain on disposal                                         |       | 161        |       |
| Income tax                                               |       | 41         |       |
| **Gain  from discontinued operations**                   | ** ** | **$**      | **94**     | ** ** |

 

**Note 13—Income Taxes**

 

We adopted the provisions ofFASB Interpretation No. 48, “Accountingfor Uncertainty in**Income Taxes,”**on January 1, 2007. Wedecreased our estimate of unrecognized tax benefits by an immaterial amountduring the quarter ended March 31, 2008 as a review of certain amendedreturns by the Joint Committee on Taxation was completed. The Joint Committeeaccepted our tax position which led us to recognize certain tax benefitspreviously unrecognized. We do not expect any significant changes to our unrecognizedtax benefits over the next twelve months. The reserve balance related tounrecognized tax benefits as of December 31, 2008 was $2,176,000 and hasnot materially changed at March 31, 2009.

 

Our consolidated provision for income taxes increased approximately$2.4 million during the first quarter of 2009 as compared to the same period in2008 mainly due to increased income. Our consolidated effective federal andstate income tax rate for the first quarter of 2009 was 33.9% as compared to30.8% for the first quarter of 2008. Ourconsolidated provision for income taxes increased approximately $5.7 millionduring the twelve months ended March 31, 2009 as compared to the twelvemonths ended March 31, 2008. Our effective federal and state income taxrate for the twelve months ended March 31, 2009 was 33.1% as compared to30.9% for the same period in 2008. The rate in both periods is higher primarilydue to lower tax benefits received from cost of plant retirement expenditures.Our cost of retirement expenditures was unusually high during the twelve monthsended March 31, 2008 due to the ice storms we experienced. This reducedbenefit during this period was partially offset by an increase in the taxeffects of equity AFUDC.

 

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**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 subsidiary.It provides natural gas distribution to customers in 44 communities innorthwest, north central and west central Missouri. Our other segment consistsof our non-regulated businesses, primarily, a 100% interest in Empire DistrictIndustries, Inc., a subsidiary for our fiber optics business. During thetwelve months ended March 31, 2009, 86.3% of our gross operating revenueswere provided from sales from our electric segment (including 0.3% from thesale of water), 12.8% from our gas segment and 0.9% from our other segment.

 

***Earnings***

 

During the first quarter of 2009, basic anddiluted earnings per weighted average share of common stock were $0.32 ascompared to $0.21 in the first quarter of 2008. For the twelve months ended March 31,2009, basic and diluted earnings per weighted average share of common stockwere $1.29 as compared to $1.14 for the twelve months ended March 31,2008. As reflected in the table below, the primary positive drivers for boththe first quarter of 2009 and the twelve months ended March 31, 2009 werereduced electric fuel and purchased power costs and increased electric revenuesprimarily due to the August 2008 Missouri rate increase (discussed below),partially offset by negative weather and other related factors. The primarynegative****driver****was****increased maintenance costs for both periods.

 

The following reconciliation of basicearnings per share between the three months and twelve months ended March 31,2008 versus March 31, 2009 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, 2008 and 2009 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.

 

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| ** **                                   | ** ** | **Three Months  Ended** | ** ** | **Twelve Months  Ended** | ** ** |
|----------------------------------------------|------------|------------------------------|------------|-------------------------------|------------|
| **Earnings  Per Share — 2008**          | ** ** | **$**                        | **0.21**   | ** **                    | **$**      | **1.14** | ** ** |
|                                         |       |                         |       |                          |       |
| **Revenues**                                 |       |                         |       |                          |       |
| Electric  on-system                          |       | $                            | 0.03       |                          | $          | 0.10 |   |
| Electric off —  system and other        |       | (0.07                        | )          | 0.07                          |       |
| Gas                                          |       | 0.02                         |       | 0.14                          |       |
| Other                                        |       | 0.00                         |       | 0.03                          |       |
| **Expenses**                                 | ** ** | ** **                   | ** ** | ** **                    | ** ** |
| Electric fuel  and purchased power           |       | 0.20                         |       | 0.19                          |       |
| Cost of natural  gas sold and transported    |       | (0.03                        | )          | (0.17                         | )          |
| Regulated —  electric segment           |       | 0.02                         |       | 0.02                          |       |
| Regulated —gas  segment                 |       | (0.01                        | )          | (0.01                         | )          |
| Other segment                                |       | 0.00                         |       | (0.01                         | )          |
| Maintenance and  repairs                     |       | (0.04                        | )          | (0.08                         | )          |
| Depreciation and  amortization               |       | 0.02                         |       | 0.02                          |       |
| Other taxes                                  |       | (0.01                        | )          | (0.01                         | )          |
| Interest charges                             |       | (0.03                        | )          | (0.11                         | )          |
| AFUDC                                        |       | 0.02                         |       | 0.12                          |       |
| Change in  effective income tax rates        |       | (0.02                        | )          | (0.05                         | )          |
| Gain on sale of  assets                      |       | —                       |       | (0.03                         | )          |
| Dilutive effect  of additional shares issued |       | —                       |       | (0.08                         | )          |
| Other income and  deductions                 |       | 0.01                         |       | 0.01                          |       |
| **Earnings  Per Share — 2009**          | ** ** | **$**                        | **0.32**   | ** **                    | **$**      | **1.29** | ** ** |

 

**RecentActivities**

 

***Equity Distribution Program***

 

On February 25, 2009,we entered into an equity distribution agreement with UBS Securities LLC (UBS).Under the terms of the agreement, we may offer and sell shares of our commonstock, par value $1.00 per share, having an aggregate offering price of up to$60 million from time to time through UBS, as sales agent. We intend to use thenet proceeds from this equity distribution program to repay short-term debt andfor general corporate purposes, including to fund our current constructionprogram. As of April 30, 2009, no shares have been sold pursuant to thisprogram.

 

Any sales of the sharespursuant to the equity distribution agreement will be made by means of ordinarybrokers’ transactions on the New York Stock Exchange at market prices or asotherwise agreed with UBS. Under the terms of the program agreement, we mayalso sell shares to UBS as principal for UBS’ own account at a price agreedupon at the time of sale.

 

***Financings***

 

On March 27, 2009, weissued $75 million principal amount of 7% first mortgage bonds due April 1,2024. The net proceeds (after payment of expenses) of approximately $72.7 million, were used to repayshort-term debt incurred, in part, to fund our current construction program.

 

On March 11, 2009, weentered into a $50 million unsecured credit agreement. This agreement providesfor $50 million of revolving loans to be available to us for working capital,general corporate purposes and to back-up our use of commercial paper andterminates on July 15, 2010. This credit agreement is in addition to, andhas substantially the same terms as (other than pricing), our Amended andRestated Unsecured Credit Agreement dated March 14, 2006. There were noborrowings under the new agreement at March 31, 2009.

 

***Regulatory Matters***

 

All pending applications forrehearing in our 2006 rate case were denied by the MPSC on November 20,2008. On December 15, 2008, the OPC filed a Petition for Writ of Reviewwith the Cole County Circuit Court regarding the MPSC’s decisions in our 2006rate case. Praxair and 

 

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ExplorerPipeline filed a Petition for Writ of Review on December 19, 2008. Theseactions were consolidated into one proceeding. Briefs have been filed by allparties.

 

Foradditional information, see “Rate Matters” below.

 

**RESULTS OF OPERATIONS**

 

The following discussion analyzes significant changes in the results ofoperations for the three-month and twelve-month periods ended March 31,2009, compared to the same periods ended March 31, 2008.

 

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

 
| ** **                           | ** ** | **Three Months Ended** | ** ** | **Twelve Months Ended** | ** ** |
|--------------------------------------|------------|----------------------------------|------------|-----------------------------------|------------|
| ** **                           | ** ** | **2009**                         | ** ** | **2008**                          | ** ** | **2009** | ** ** | **2008** | ** ** |
|                                 |       |                             |       |                              |       |   |   |   |   |
| Income from  continuing operations   |       |                             |       |                              |       |   |   |   |   |
| Electric                             |       | $                                | 8.8        |                              | $          | 4.4 |   | $ | 41.9 |   | $ | 33.3 |   |
| Gas                                  |       | 1.8                              |       | 2.4                               |       | 1.0 |   | 1.8 |   |
| Other                                |       | 0.3                              |       | 0.2                               |       | 0.8 |   | 0.5 |   |
| Income from  continuing operations   |       | $                                | 10.9       |                              | $          | 7.0 |   | $ | 43.7 |   | $ | 35.6 |   |
| Income from  discontinued operations |       | —                           |       | —                            |       | — |   | 0.1 |   |
| Net income*                          |       | $                                | 10.9       |                              | $          | 7.0 |   | $ | 43.7 |   | $ | 35.7 |   |

 

----

**Differences could occur due to rounding.*

 

***Electric Segment***

 

**Overview**

 

Our electric segment income for the first quarter of 2009 was $8.8million as compared to $4.4 million for the first quarter of 2008.

 

Electric operating revenues comprised approximately 78.2% of our totaloperating revenues during the first quarter of 2009. Of our total electricoperating revenues during the first quarter of 2009, approximately 45.7% werefrom residential customers, 27.9% from commercial customers, 14.0% from industrialcustomers, 4.4% from wholesale on-system customers, 3.7% from wholesaleoff-system transactions, 2.6% from other electric revenues, primarily publicauthorities and 1.7% from miscellaneous sources. The percentage of revenuesprovided from our wholesale off-system transactions decreased during the firstquarter of 2009 as compared to the first quarter of 2008 primarily due todecreased market demand resulting from mild weather in the first quarter of2009.

 

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

 
| ** **              | ** ** | **kWh Sales  (in millions)** | ** ** |
|-------------------------|------------|----------------------------------------|------------|
| ** **              | ** ** | **First**                              | ** ** | **First** | ** ** | ** ** | ** ** | **12 Months** | ** ** | **12 Months** | ** ** | ** ** | ** ** |
| ** **              | ** ** | **Quarter**                            | ** ** | **Quarter** | ** ** | **%** | ** ** | **Ended** | ** ** | **Ended** | ** ** | **%** | ** ** |
| **Customer Class** | ** ** | **2009**                               | ** ** | **2008** | ** ** | **Change*** | ** ** | **2009** | ** ** | **2008** | ** ** | **Change*** | ** ** |
| Residential             |       | 550.9                                  |       | 593.5 |   | (7.2 | )% | 1,910.3 |   | 1,978.8 |   | (3.5 | )% |
| Commercial              |       | 376.0                                  |       | 379.0 |   | (0.8 | ) | 1,619.1 |   | 1,632.0 |   | (0.8 | ) |
| Industrial              |       | 240.2                                  |       | 262.0 |   | (8.3 | ) | 1,051.5 |   | 1,116.9 |   | (5.9 | ) |
| Wholesale  on-system    |       | 80.8                                   |       | 85.4 |   | (5.5 | ) | 339.9 |   | 347.6 |   | (2.2 | ) |
| Other**                 |       | 32.2                                   |       | 32.0 |   | 0.6 |   | 123.9 |   | 120.7 |   | 2.7 |   |
| Total on-system  sales  |       | 1,280.1                                |       | 1,351.9 |   | (5.3 | ) | 5,044.7 |   | 5,196.0 |   | (2.9 | ) |
| Off-system              |       | 133.9                                  |       | 140.4 |   | (4.6 | ) | 681.7 |   | 511.8 |   | 33.2 |   |
| Total KWh Sales         |       | 1,414.0                                |       | 1,492.3 |   | (5.2 | ) | 5,726.4 |   | 5,707.8 |   | 0.3 |   |

 

----

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

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

 

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| ** **                         | ** ** | **Electric Segment Operating Revenues  (in millions)** | ** ** |
|------------------------------------|------------|----------------------------------------------------------------------------|------------|
| ** **                         | ** ** | **First**                                                                  | ** ** | **First** | ** ** | ** ** | ** ** | **12  Months** | ** ** | **12  Months** | ** ** | ** ** | ** ** |
| ** **                         | ** ** | **Quarter**                                                                | ** ** | **Quarter** | ** ** | **%** | ** ** | **Ended** | ** ** | **Ended** | ** ** | **%** | ** ** |
| **Customer Class**            | ** ** | **2009**                                                                   | ** ** | **2008** | ** ** | **Change*** | ** ** | **2009** | ** ** | **2008** | ** ** | **Change*** | ** ** |
| Residential                        |       | $                                                                          | 48.6       |   | $ | 48.6 |   | (0.1 | )% | $ | 179.2 |   | $ | 178.5 |   | 0.4 | % |
| Commercial                         |       | 29.7                                                                       |       | 27.9 |   | 6.3 |   | 134.6 |   | 130.6 |   | 3.1 |   |
| Industrial                         |       | 14.9                                                                       |       | 14.8 |   | 0.2 |   | 67.4 |   | 68.1 |   | (1.0 | ) |
| Wholesale  on-system               |       | 4.7                                                                        |       | 5.1 |   | (7.3 | ) | 18.9 |   | 19.2 |   | (1.9 | ) |
| Other**                            |       | 2.7                                                                        |       | 2.6 |   | 7.7 |   | 11.2 |   | 10.4 |   | 8.0 |   |
| Total on-system  revenues          |       | $                                                                          | 100.6      |   | $ | 99.0 |   | 1.6 |   | $ | 411.3 |   | $ | 406.8 |   | 1.1 |   |
| Off-system                         |       | 4.0                                                                        |       | 7.5 |   | (46.8 | ) | 26.2 |   | 23.5 |   | 11.4 |   |
| Total Revenues  from KWh Sales     |       | 104.6                                                                      |       | 106.5 |   | (1.8 | ) | 437.5 |   | 430.3 |   | 1.7 |   |
| Miscellaneous  Revenues***         |       | 1.8                                                                        |       | 1.8 |   | (0.6 | ) | 7.0 |   | 6.2 |   | 11.6 |   |
| Total Electric  Operating Revenues |       | $                                                                          | 106.4      |   | $ | 108.3 |   | (1.8 | ) | $ | 444.5 |   | $ | 436.5 |   | 1.8 |   |
| Water Revenues                     |       | 0.4                                                                        |       | 0.4 |   | (2.7 | ) | 1.8 |   | 1.9 |   | (5.0 | ) |
| Total Electric  Segment Operating  |       |                                                                       |       |   |   |   |   |   |   |   |   |   |   |
| Revenues                           |       | $                                                                          | 106.8      |   | $ | 108.7 |   | (1.8 | ) | $ | 446.3 |   | $ | 438.4 |   | 1.8 |   |

 

----

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

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

****Miscellaneous revenues include transmission service revenue, latepayment fees, rent, etc.*

 

***Quarter Ended March 31, 2009 Compared toQuarter Ended March 31, 2008***

 

**Operating Revenues and Kilowatt-Hour Sales**

 

KWh sales for our on-system customers decreased during the firstquarter of 2009 as compared to the first quarter of 2008 primarily due to milderweather in 2009. Revenues for our on-system customers increased approximately$1.6 million, or 1.6%. Rate changes, primarily the August 2008 Missourirate increase (discussed below), contributed an estimated $7.0 million torevenues while continued sales growth contributed an estimated $0.4 million.Our electriccustomergrowth for the twelve months ended March 31, 2009 was 0.1%. Weather andother related factors decreased revenues an estimated $5.8 million. Totalheating degree days (the sum of the number of degrees that the daily averagetemperature for each day during that period was below 65*°* F) for the first quarter of 2009 were 6.8%less than the same period last year and 6.4% less than the 30-year average.

 

During the first quarter of 2009, the decrease in residential kWh salesand slight decrease in residential revenues (which were partially offset by theAugust 2008 Missouri rate increase) was primarily due to the mild weatherin the first quarter of 2009. The decrease in commercial kWh sales was mainlydue to the mild weather while the increase in commercial revenues was primarilydue to the aforementioned Missouri rate increase.

 

Industrial kWh sales decreased 8.3% mainly due to a slowdown created byeconomic uncertainty while the associated revenues increased 0.2% due to theeffects of the Missouri rate increase which partially offset the economicconditions**.**

 

On-system wholesale kWh sales decreased during the first quarter of2009 as compared to the same period in 2008 reflecting the mild weather in thefirst quarter of 2009. Revenues associated with these FERC-regulated salesdecreased more than sales as a result of the fuel adjustment clause applicableto such sales. This clause permits the distribution to customers of changes infuel and purchased power costs.

 

**Off-System Electric Transactions**

 

In addition tosales to our own customers, we also sell power to other utilities as available,including through the Southwest Power Pool (SPP) energy imbalance services(EIS) market. See “— Competition” below. The majority of our off-system salesmargins are now included as a component of the fuel adjustment clause in ourMissouri, Kansas and Oklahoma jurisdictions and generally adjust the fuel andpurchased power expense. The MPSC authorized a fuel adjustment 

 

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clause for ourMissouri customers (effective September 1, 2008) which established a basecost for the recovery of fuel and purchased power expenses used to supplyenergy. The clause permits the distribution to customers of 95% of the changesin fuel and purchased power costs above or below the base cost. Off-systemsales margins are also part of the recovery of fuel and purchased power costs.As a result, the off-system sales margin flows back to the customer. Thefollowing table sets forth information regarding these sales and relatedexpenses for the quarters ended March 31:

** **
| **(in millions)**     | ** ** | **2009**   | ** ** | **2008**   | ** ** |
|----------------------------|------------|------------|------------|------------|------------|
| ** **                 | ** ** | ** ** | ** ** | ** ** | ** ** |
| EIS revenues               |       | $          | 1.5        |       | $          | 3.0 |   |
| Other revenues             |       | 2.5        |       | 4.5        |       |
| Total off-system  revenues |       | 4.0        |       | 7.5        |       |
|                       |       |       |       |       |       |
| EIS expenses               |       | 1.2        |       | 2.3        |       |
| Other expenses             |       | 2.0        |       | 3.4        |       |
| Total off-system  expenses |       | 3.2        |       | 5.7        |       |
|                       |       |       |       |       |       |
| Net                        |       | $          | 0.8        |       | $          | 1.7 |   |

 

----

**Differences could occur due to rounding.*

 

Revenues and related expenses were less during the first quarter of2009 as compared to the first quarter of 2008 primarily due to decreased marketdemand resulting from the mild weather in the first quarter of 2009. Totalpurchased power related expenses are included in our discussion of purchasedpower costs below.

 

**Miscellaneous Revenues**

 

Our miscellaneous revenues were $1.8 million for both the first quarterof 2009 and the first quarter of 2008. These revenues are comprised mainly oftransmission revenues, late payment fees and renewable energy credit sales.

 

**Operating Revenue Deductions**

 

During the first quarter of 2009, total electric segment operatingexpenses decreased approximately $6.7 million (6.9%) compared with the sameperiod last year.

 

Total fuel and purchasedpower expenses decreased approximately $10.2 million (17.8%) during the firstquarter of 2009. The table below is a reconciliation of our actual fuel andpurchased power expenditures (netted with the regulatory adjustments) to thefuel and purchased power expense shown on our statement of operations for thefirst quarter of 2009 and 2008.

 
| **(in millions)**                                       | ** ** | **2009** | ** ** | **2008** | ** ** |
|--------------------------------------------------------------|------------|----------|------------|----------|------------|
| Actual fuel and  purchased power expenditures                |       | $        | 49.7       |     | $          | 57.4 |   |
| Kansas  regulatory adjustments*                              |       | 0.3      |       | (0.5     | )          |
| Missouri  regulatory adjustments*                            |       | (3.1     | )          | —   |       |
| Unrealized loss  on derivatives                              |       | (0.1     | )          | —   |       |
| Total fuel and  purchased power expense per income statement |       | $        | 46.8       |     | $          | 56.9 |   |

 

----

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

 

The overall fuel andpurchased power decrease reflects decreased generation by our gas fired unitsand a decrease in purchased power in the first quarter of 2009 as compared to2008 when we had an extended outage at the Asbury plant lasting from the fourthquarter of 2007 into the first quarter of 2008. The decrease in fuel costs alsoincludes theeffect ofdecreased market demand resulting from mild weather in the first quarter of2009 as well as decreased costs for****off-systemsales of $2.5 million**.**

 

Summarized in the tablebelow are our estimated cost and volume changes in the components of fuel andpurchased power expenses for the first quarter of 2009 as when compared 

 

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tothe first quarter of 2008. This table incorporates all the changes mentionedabove. As shown below, the largest impact on fuel and purchased power costs wasa decrease in generation by our gas-fired units.

 
| **(in millions)**                          | ** ** | **2008** | ** ** |
|-------------------------------------------------|------------|----------|------------|
| Purchased power  (cost per mWh)                 |       | $        | (3.4       | ) |
| Purchased power  spot purchase volume           |       | 0.1      |       |
| Coal (cost per  mWh)                            |       | 1.5      |       |
| Coal generation  volume                         |       | 0.1      |       |
| Natural gas  (cost per mWh)                     |       | (2.3     | )          |
| Natural gas  generation volume                  |       | (5.9     | )          |
| Natural gas —  gain on unwind of positions |       | 2.1      |       |
| Other (including  fuel adjustments)             |       | (2.4     | )          |
| TOTAL                                           |       | $        | (10.2      | ) |

 

Regulated operating expensesdecreased approximately $0.7 million (4.8%) during the first quarter of 2009 ascompared to the same period in 2008 primarily due to decreases of $0.7 millionin employee health care expense, $0.2 million in employee pension expense, $0.2million in injuries and damages expense, $0.2 million in general labor costs,$0.1 million in transmission and distribution expense,****$0.1million in other power operation expense and $0.1 million in regulatorycommission expense. These decreases were partially offset by increases of $0.3 millionin professional services, $0.3 million in other steam power expense and $0.2million in other power supply expense.

 

Maintenance and repairs expense increased approximately $2.2 million(41.1%) in the first quarter of 2009 as compared to the first quarter of 2008mainly due to increases of approximately $1.5 million in distributionmaintenance costs (including $1.0 million of ice storm related amortization and$0.3 million related to our vegetation tracker), $0.6 million in other powermaintenance expense which is primarily due to the State Line Combined Cycle(SLCC) maintenance outage and $0.1 million in steam power maintenance expense.

 

Depreciation and amortization expense decreased approximately $1.0million (7.7%) during the quarter primarily due to reduced regulatoryamortization resulting from the 2008 Missouri rate case that went into effecton August 23, 2008. Other taxes increased approximately $0.2 millionduring the first quarter of 2009 due to increased property tax reflecting ouradditions to plant in service and increased municipal franchise taxes.

 

***Twelve Months Ended March 31, 2009 Compared toTwelve Months Ended March 31, 2008***

 

**Operating Revenues and Kilowatt-Hour Sales**

 

For the twelve months ended March 31, 2009, kWh sales to our on-systemcustomers decreased 2.9% with the associated revenues increasing approximately$4.6 million (1.1%). Rate changes, primarily the August 2008 Missouri rateincrease (discussed below), contributed an estimated $16.2 million to revenueswhile continued sales growth contributed an estimated $6.0 million. Weather andother related factors decreased revenues an estimated $17.6 million. Thedecrease in residential and commercial kWh sales during the twelve months endedMarch 31, 2009 was primarily due to mild weather in the first quarter of2009 and the third quarter of 2008. The increase in residential and commercialrevenues was primarily due to the 2008 Missouri rate increase. Industrial kWhsales decreased 5.9% mainly due to a slowdown created by economic uncertaintywhile the associated revenues decreased 1.0%, reflecting the economicconditions, partially offset by the Missouri rate increase**.**On-systemwholesale kWh sales decreased during the twelve months ended March 31,2009 reflecting the mild weather in the first quarter of 2009. Revenuesassociated with these FERC-regulated sales decreased less than the kWh sales asa result of the fuel adjustment clause applicable to such sales.

 

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**Off-System Electric Transactions**

 

In addition to sales to ourown customers, we also sell power to other utilities as available, includingthrough the SPP EIS market. See “— Competition” below. The majority of ouroff-system sales margins are now included as a component of the fuel adjustmentclause in our Missouri, Kansas and Oklahoma jurisdictions and generally adjustthe fuel and purchased power expense. The following table sets forthinformation regarding these sales and related expenses for the twelve monthsended March 31:

 
| **(in millions)**     | ** ** | **2009**   | ** ** | **2008**   | ** ** |
|----------------------------|------------|------------|------------|------------|------------|
| ** **                 | ** ** | ** ** | ** ** | ** ** | ** ** |
| EIS revenues               |       | $          | 11.5       |       | $          | 9.9 |   |
| Other revenues             |       | 14.7       |       | 13.6       |       |
| Total off-system  revenues |       | 26.2       |       | 23.5       |       |
|                       |       |       |       |       |       |
| EIS expenses               |       | 8.2        |       | 7.5        |       |
| Other expenses             |       | 10.8       |       | 10.0       |       |
| Total off-system  expenses |       | 19.0       |       | 17.5       |       |
|                       |       |       |       |       |       |
| Net                        |       | $          | 7.2        |       | $          | 6.0 |   |

 

----

**Differences could occur due to rounding.*

 

Revenues increased during the twelve months ended March 31, 2009as compared to the same period in 2008 primarily due to sales facilitated bythe EIS market**.**Total purchased power related expenses areincluded in our discussion of purchased power costs below.

 

**Miscellaneous Revenues**

 

Our miscellaneous revenues for the twelve months ended March 31,2009 were $7.0 million as compared to $6.2 million in the same period of 2008.These revenues are comprised mainly of transmission revenues, late payment feesand renewable energy credit sales.

 

**Operating Revenue Deductions**

 

During the twelve months ended March 31, 2009, total electricsegment operating expenses increased approximately $0.7 million (0.2%) comparedto the year ago period.

 

Totalfuel and purchased power costs decreased approximately $8.8 million (4.4%)during the twelve months ended March 31, 2009. The table below is areconciliation of our actual fuel and purchased power expenditures (netted withthe regulatory adjustments) to the fuel and purchased power expense shown onour statement of operations for the twelve months ended March 31, 2009.

 
| **(in millions)**                                       | ** ** | **2009** | ** ** | **2008** | ** ** |
|--------------------------------------------------------------|------------|----------|------------|----------|------------|
| Actual fuel and  purchased power expenditures                |       | $        | 196.3      |     | $          | 203.0 |   |
| Kansas  regulatory adjustments*                              |       | 0.2      |       | (0.3     | )          |
| Missouri  regulatory adjustments*                            |       | (2.9     | )          | —   |       |
| Unrealized loss  on derivatives                              |       | 0.3      |       | —   |       |
| Total fuel and  purchased power expense per income statement |       | $        | 193.9      |     | $          | 202.7 |   |

 

----

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

 

The overall fuel andpurchased power decrease includes theeffect of decreased market demand resulting from mild weather in thefirst quarter of 2009 and the third quarter of 2008, as well as****the effects of an extended outage at the Asbury plantlasting from the fourth quarter of 2007 into the first quarter of 2008 duringwhich time we relied on purchased power and our gas-fired units to replace ourcoal-fired generation. These decreases were partially offset by increased costsfor****off-system sales of $1.5 million

 

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Summarized in the tablebelow are our estimated cost and volume changes in the components of fuel andpurchased power expenses for the twelve months ended March 31, 2009 aswhen compared to the twelve months ended March 31, 2008. This tableincorporates all the changes mentioned above. As shown below, the largestimpact on fuel and purchased power costs was a decrease in generation by ourgas-fired units.

 
| **(in millions)**                          | ** ** | **2009** | ** ** |
|-------------------------------------------------|------------|----------|------------|
| Purchased power  (cost per mWh)                 |       | $        | 3.0        |   |
| Purchased power  spot purchase volume           |       | (1.8     | )          |
| Coal (cost per  mWh)                            |       | 4.8      |       |
| Coal generation  volume                         |       | 4.2      |       |
| Natural gas  (cost per mWh)                     |       | (6.2     | )          |
| Natural gas  generation volume                  |       | (12.9    | )          |
| Natural gas —  gain on unwind of positions |       | 2.1      |       |
| Other (including  fuel adjustments)             |       | (2.0     | )          |
| TOTAL                                           |       | $        | (8.8       | ) |

 

Regulated operating expensesdecreased approximately $0.9 million (1.4%) during the twelve months ended March 31,2009 as compared to the same period in 2008 primarily due to decreases of $1.6million in employee health care expense, $0.7 million in employee pensionexpense, $0.6 million in uncollectible accounts expense, $0.5 million ingeneral labor costs, $0.2 million in other power operation expense and $0.2million in regulatory commission expense. These decreases were partially offsetby increases of $0.9 million in other steam power expense, $0.8 million intransmission and distribution expense,****$0.5 millionin other power supply expense, $0.4 million in injuries and damages expense,$0.2 million in property insurance expense, $0.1 million in professionalservices, and $0.1 million in director and stockholder expense.

 

Maintenance and repairsexpense increased approximately $4.3 million (16.9%) during the twelve monthsended March 31, 2009 as compared to the twelve months ended March 31,2008 primarily due to increases of approximately $2.3 million in distributionmaintenance costs (including $2.3 million of ice storm related amortization), $0.9 million in maintenance and repairsexpense at the SLCC plant due to the first quarter 2009 maintenance outage andthe extended spring maintenance outage in the second quarter of 2008, $0.9 million in maintenance and repairsexpense at the Iatan plant due to an outage in the fourth quarter of 2008, $0.6 million in maintenance andrepairs expense at the Riverton plant mainly due to the extended outage on Unit8 to repair damage to high pressure blades discovered during Riverton’sscheduled maintenance outage in May 2008, $0.2 million in transmissionexpense and $0.1 million in maintenance costs for the Riverton gas-fired units.These increases were partially offset by a $0.4 million decrease in maintenanceand repairs expense at the Asbury plant as compared to the twelve months ended March 31,2008 period when there was an extended outage during the fourth quarter of2007, and a $0.4 million decrease in maintenance expense at the Energy Centerplant as compared to the 12 month period ended March 31, 2008 when therewas a bearing failure in Unit #3 in the second quarter of 2007.

 

Depreciation and amortization expense decreased approximately $1.1million (2.3%) during the twelve months ended March 31, 2009 primarily dueto reduced regulatory amortization resulting from the 2008 Missouri rate casethat went into effect on August 23, 2008. Other taxes increasedapproximately $0.2 million during the twelve months ended March 31, 2009due to increased property tax reflecting our additions to plant in service andincreased municipal franchise taxes.

 

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***Gas Segment***

 

**Gas Operating Revenues and Sales**

 

**Total gas delivered to customers**

 
| ** **                 | ** ** | **Three Months Ended** | ** ** | **Twelve Months Ended** | ** ** |
|----------------------------|------------|----------------------------------|------------|-----------------------------------|------------|
| ** **                 | ** ** | **bcf sales**               | ** ** | **bcf sales**                | ** ** | ** ** | ** ** | **bcf sales** | ** ** | **bcf sales** | ** ** | ** ** | ** ** |
| ** **                 | ** ** | **2009**                         | ** ** | **2008**                          | ** ** | **% change** | ** ** | **2009** | ** ** | **2008** | ** ** | **% change** | ** ** |
| Residential                |       | 1.31                             |       | 1.53                              |       | (14.3 | )% | 2.73 |   | 3.00 |   | (8.9 | )% |
| Commercial                 |       | 0.57                             |       | 0.67                              |       | (15.4 | ) | 1.29 |   | 1.40 |   | (7.3 | ) |
| Industrial*                |       | 0.15                             |       | 0.05                              |       | 206.2 |   | 0.66 |   | 0.11 |   | 507.1 |   |
| Other**                    |       | 0.02                             |       | 0.02                              |       | (16.6 | ) | 0.03 |   | 0.03 |   | (4.7 | ) |
| Total retail  sales        |       | 2.05                             |       | 2.27                              |       | (9.8 | ) | 4.71 |   | 4.54 |   | 3.9 |   |
| Transportation  sales**    |       | 1.16                             |       | 1.36                              |       | (14.8 | ) | 3.86 |   | 4.30 |   | (10.5 | ) |
| Total gas  operating sales |       | 3.21                             |       | 3.63                              |       | (11.7 | ) | 8.57 |   | 8.84 |   | (3.1 | ) |

 

----

**Percentagechange reflects the transfer of a customer from transportation sales toindustrial.*

***Otherincludes other public authorities and interdepartmental usage.*

 

**Operating Revenues and Cost of Gas Sold**

 
| ** **                                        | ** ** | **Three Months Ended** | ** ** | **Twelve Months Ended** | ** ** |
|---------------------------------------------------|------------|----------------------------------|------------|-----------------------------------|------------|
| **($ in millions)**                     | ** ** | **2009**                         | ** ** | **2008**                          | ** ** | **% change** | ** ** | **2009** | ** ** | **2008** | ** ** | **% change** | ** ** |
| Residential                                       |       | $                                | 18.1       |                              | $          | 18.1 |   | 0.0 | % | $ | 39.6 |   | $ | 38.7 |   | 2.5 | % |
| Commercial                                        |       | 7.4                              |       | 7.5                               |       | (0.7 | ) | 17.4 |   | 16.5 |   | 4.9 |   |
| Industrial*                                       |       | 1.4                              |       | 0.4                               |       | 229.2 |   | 6.1 |   | 1.0 |   | 512.8 |   |
| Other**                                           |       | 0.2                              |       | 0.2                               |       | (2.4 | ) | 0.4 |   | 0.4 |   | 10.1 |   |
| Total retail  revenues                            |       | $                                | 27.1       |                              | $          | 26.2 |   | 3.5 |   | $ | 63.5 |   | $ | 56.6 |   | 12.1 |   |
| Other revenues                                    |       | 0.1                              |       | 0.1                               |       | 16.8 |   | 0.2 |   | 0.2 |   | 10.1 |   |
| Transportation  revenues*                         |       | 0.9                              |       | 1.0                               |       | (11.5 | ) | 2.5 |   | 2.7 |   | (7.2 | ) |
| Total gas  operating revenues                     |       | $                                | 28.1       |                              | $          | 27.3 |   | 3.0 |   | $ | 66.2 |   | $ | 59.5 |   | 11.2 |   |
| Cost of gas sold                                  |       | 19.3                             |       | 17.7                              |       | 9.1 |   | 44.2 |   | 36.6 |   | 20.8 |   |
| Gas operating  revenues over cost of gas in rates |       | $                                | 8.8        |                              | $          | 9.6 |   | (8.3 | ) | $ | 22.0 |   | $ | 22.9 |   | (4.1 | ) |

 

----

**Percentagechange reflects the transfer of a customer from transportation sales toindustrial.*

***Otherincludes other public authorities and interdepartmental usage.*

 

***Quarter Ended March 31, 2009 Compared toQuarter Ended March 31, 2008***

 

**Operating Revenues and bcf Sales**

 

Gas retail sales decreased9.8% during the first quarter of 2009 as compared to 2008 primarily due to mildweather in the first quarter of 2009. The winter months are normally high salesmonths for the natural gas business, whose heating season runs from November toMarch of each year. Residential sales decreased 14.3% and commercial salesdecreased 15.4% during the first quarter of 2009 as compared to the firstquarter of 2008 primarily due to milder weather. Heating degree days were 13.9%lower in the first quarter of 2009 as compared to the first quarter of 2008.Industrial sales increased during the first quarter of 2009 as compared to thesame period in 2008 due to the transfer of a large volume interruptiblecustomer from transportation to sales service and the addition of a new largevolume interruptible customer in the third quarter of 2008.

 

During the first quarter of2009, gas segment revenues were approximately $28.1 million as compared to$27.3 million in the first quarter of 2008, an increase of 3.0% despite thedecrease in sales. During the first quarter of 2009, our PGA revenue (which represents the cost of gas recoveredfrom our customers) was approximately $19.3 million as compared to $17.7million in the first quarter of 2008, an increase of approximately $1.6million. This increase was largely driven by the increase in industrial salesand an increase in PGA revenues.

 

Our PGA clause allows us torecover from our customers, subject to routine regulatory review, the cost ofpurchased gas supplies, transportation and storage, including costs associatedwith the use of financial instruments to hedge the purchase price of naturalgas. Pursuant to the provisions of the PGA clause, the difference betweenactual costs incurred and costs recovered through the application of the PGAare reflected as a regulatory asset or regulatory liability until the 

 

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balance is recovered from orcredited to customers. As of March 31, 2009, we had unrecovered purchasedgas costs of $1.7 million recorded as a regulatory asset.

 

**OperatingRevenue Deductions**

 

Total other operatingexpenses were $2.9 million during the first quarter of 2009 as compared to $2.5million in the first quarter of 2008, an increase of $0.4 million. Thisincrease was mainly due to a $0.4 million increase in uncollectible accounts.EDG had net income of $1.8 million for the first quarter of 2009 as compared to$2.5 million for the first quarter of 2008.

 

***Twelve Months Ended March 31, 2009 Compared toTwelve Months Ended March 31, 2008***

 

**Operating Revenues and bcf Sales**

 

Gas retail sales increased3.9% during the twelve months ended March 31, 2009 mainly due to anincrease in industrial sales as compared to 2008. Residential and commercialsales decreased during the twelve months ended March 31, 2009 as comparedto the same period in 2008 primarily due to milder weather in the first quarterof 2009. Industrial sales increased during the twelve months ended March 31,2009 as compared to the same period in 2008 due to the transfer of a largevolume interruptible customer from transportation to sales service and theaddition of a new large volume interruptible customer in the third quarter of2008.

 

During the twelve monthsended March 31, 2009, gas segment revenues were approximately $66.2million as compared to $59.5 million in the twelve months ended March 31,2008, an increase of 11.2%, reflecting the higher overall sales. This increasewas largely driven by the increase in industrial sales and PGA revenue. Duringthe twelve months ended March 31, 2009, our PGA revenue was approximately$44.2 million as compared to $36.6 million during the twelve months ended March 31,2008, an increase of approximately $7.6 million.

 

**OperatingRevenue Deductions**

 

Total other operatingexpenses were $10.4 million for the twelve months ended March 31, 2009 ascompared to $9.9 million for the twelve months ended March 31, 2008. Thisincrease was mainly due to a $0.7 million increase in customer accountsexpense. EDG had net income of $1.0 million for the twelve months ended March 31,2009 as compared to $1.8 million for the twelve months ended March 31,2008.

 

***Other Segment***

 

Our other segment consists of ournon-regulated business, primarily the leasing of fiber optics cable andequipment (which we are also using in our own utility operations). Thefollowing table represents the results for our other segment for the applicableperiods ended March 31 (in millions):

 
| ** ** | ** ** | **Three Months Ended** | ** ** | **Twelve Months Ended** | ** ** |
|------------|------------|----------------------------------|------------|-----------------------------------|------------|
| ** ** | ** ** | **2009**                         | ** ** | **2008**                          | ** ** | **2009** | ** ** | **2008** | ** ** |
| Revenues   |       | $                                | 1.3        |                              | $          | 1.1 |   | $ | 5.2 |   | $ | 3.9 |   |
| Expenses   |       | 1.0                              |       | 0.9                               |       | 4.5 |   | 3.4 |   |
| Net income |       | $                                | 0.3        |                              | $          | 0.2 |   | $ | 0.7 |   | $ | 0.5 |   |

 

----

**Differences could occur due to rounding.*

 

***Consolidated Company***

 

**Income Taxes**

 

Our consolidated provision for income taxes increased approximately$2.4 million during the first quarter of 2009 as compared to the same period in2008 mainly due to increased income. Our consolidated effective federal andstate income tax rate for the first quarter of 2009 was 33.9% as 

 

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compared to 30.8% for thefirst quarter of 2008. Our consolidatedprovision for income taxes increased approximately $5.7 million during thetwelve months ended March 31, 2009 as compared to the twelve months ended March 31,2008. Our effective federal and state income tax rate for the twelve monthsended March 31, 2009 was 33.1% as compared to 30.9% for the same period in2008. The rate in both periods is higher primarily due to lower tax benefitsreceived from cost of plant retirement expenditures. Our cost of retirementexpenditures was unusually high during the twelve months ended March 31,2008 due to the ice storms we experienced. This reduced benefit during thisperiod was partially offset by an increase in the tax effects of equity AFUDC.

 

**Nonoperating Items**

 

Total allowance for funds used during construction (AFUDC) increased$1.1 million in the first quarter of 2009 as compared to 2008 and increased$5.6 million during the twelve months ended March 31, 2009 as compared tothe same period in 2008 due to higher levels of construction in each period.

 

Total interest charges on long-termdebt increased $1.6 million (19.3%) in the first quarter of 2009 as compared to2008 and increased $5.4 million (16.6%) for the twelve months ended March 31,2009 as compared to the prior year period. The increases in both periodsreflect the interest on the $90 million principal amount of first mortgagebonds we issued May 16, 2008 and the $75 million principal amount of firstmortgage bonds we issued March 27, 2009. Short-term debt interest wasvirtually the same in the first quarter of 2009 as compared to 2008 anddecreased $0.5 million for the twelve months ended March 31, 2009 ascompared to the prior year period, reflecting lower cost of borrowing.

 

We had no gains or lossesfrom discontinued operations in the twelve months ended March 31, 2009compared to a slight gain of less than $0.1 million for the twelve months endedMarch 31, 2008.

 

**OtherComprehensive Income**

 

The change in the fair valueof the effective portion of our open gas contracts designated as cash flowhedges entered into prior to September 1, 2008 for our electric businessand the gains and losses on contracts settled during the periods beingreported, including the tax effect of these items, are reflected in ourConsolidated Statement of Comprehensive Income. The fair value of open electricsegment derivative contracts decreased $9.3 million in the first quarter of2009, reflecting falling natural gas prices. This net change is recorded asaccumulated other comprehensive income in the capitalization section of ourbalance 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 fueland purchased power in the periods in which the hedged transaction is actuallyrealized or no longer qualifies for hedge accounting.

 

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)**                           | ** ** | **2009**                         | ** ** | **2008**                          | ** ** | **2009** | ** ** | **2008** | ** ** |
| Natural gas contracts  settled (1)               |       | $                                | 4.9        |                              | $          | (0.8 | ) | $ | 1.9 |   | $ | (2.6 | ) |
| Change in FMV of  open contracts for natural gas |       | $                                | (9.3       | )                                 | $          | 11.0 |   | $ | (37.7 | ) | $ | 13.3 |   |
| Taxes                                            |       | $                                | 1.7        |                              | $          | (3.9 | ) | $ | 13.6 |   | $ | (4.1 | ) |
| Total change in  OCI — net of tax           |       | $                                | (2.7       | )                                 | $          | 6.3 |   | $ | (22.2 | ) | $ | 6.6 |   |

 

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

 

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**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, 2007:

 
| ** **           | ** ** | ** **           | ** ** | **Annual**   | ** ** | **Percent**  | ** ** | ** **    | ** **           |
|----------------------|------------|----------------------|------------|--------------|------------|--------------|------------|---------------|----------------------|
| ** **           | ** ** | **Date**             | ** ** | **Increase** | ** ** | **Increase** | ** ** | **Date**      | ** **           |
| **Jurisdiction**     | ** ** | **Requested**        | ** ** | **Granted**  | ** ** | **Granted**  | ** ** | **Effective** | ** **           |
| Missouri -  Electric |       | October 1, 2007 |       | $            | 22,040,395 |         | 6.70       | %             | August 23, 2008 |   |
|                      |            |                      |            |              |            |              |            |               |                      |  |

 

*Missouri*

 

*2007 Rate Case*

 

The MPSC issued an order on July 30,2008 in response to a request filed with the MPSC on October 1, 2007 foran annual increase in base rates for our Missouri electric customers. Thisorder granted an annual increase in revenues for our Missouri electriccustomers in the amount of $22.0 million, or 6.7%, based on a 10.8% return onequity. The new rates went into effect August 23, 2008.

 

The order contains two components. The first component provides anaddition to base rates of approximately $27.7 million. This increase in baserates was partially offset by a $5.7 million reduction to regulatory amortization,which is the second component to support certain credit metrics of the overallchange in revenue authorized by the MPSC. Regulatory amortization provides usadditional cash through rates during the current construction cycle. Thisconstruction, which is part of our long-range plan to ensure reliability,includes the facilities at the Riverton Power Plant and Iatan 2 Power Plant, aswell as environmental improvements at the Asbury Power Plant and at Iatan 1.The regulatory amortization is now approximately $4.5 million annually and isrecorded as depreciation expense.

 

The MPSC also authorized a fuel adjustment clause for our Missouricustomers effective September 1, 2008. The MPSC established a base costfor the recovery of fuel and purchased power expenses used to supply energy.The clause permits the distribution to customers of 95% of the changes in fueland purchased power costs above or below the base cost. Off-system salesmargins are also part of the recovery of fuel and purchased power costs. As aresult, the off-system sales margin flows back to the customer. Rates relatedto the recovery of fuel and purchased power costs will be modified twice a yearsubject to the review and approval by the MPSC. In accordance with FAS 71, 95%of the difference between the actual cost of fuel and purchased power and thebase cost of fuel and purchased power recovered from our customers is recordedas an adjustment to fuel and purchased power expense with a correspondingregulatory asset or a regulatory liability. If the actual fuel and purchasedpower costs are higher or lower than the base fuel and purchased power costsbilled to customers, 95% of these amounts will be recovered or refunded to ourcustomers when the fuel adjustment clause is modified. At March 31, 2009,Missouri fuel and purchased power costs were under-recovered $2.9 million,which is reflected as a regulatory asset. On April 1, 2009, we filedproposed rate schedules with the MPSC requesting an increase of $1.9 million inrevenues we bill through our fuel adjustment clause to become effective June 1,2009.

 

The MPSC order approved a Stipulation and Agreement providing for therecovery of deferred expenses of approximately $14.2 million over a five yearperiod for the 2007 ice storms. In addition, the MPSC order required theimplementation of a two-way tracking mechanism for recovery of the costsrelating to the new MPSC rules on infrastructure inspection and vegetationmanagement. The mechanism authorized by the MPSC creates a regulatory liabilityin any year we spend less than the target amount, which has been set at $8.6million for our Missouri jurisdiction, 

 

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and a regulatory asset if we spend more than the target amount. Anyregulatory asset and liability amounts created using the tracking mechanismwill then be netted against each other and taken into account in our next ratecase. The MPSC also approved Stipulations and Agreements providing for thecontinuation of the pension and other post-retirement employee benefitstracking mechanism established in our 2006 and 2007 Missouri rate orders.

 

TheMPSC issued its Reportand Order on July 30, 2008, effective August 9, 2008. The OPC and intervenors Praxair, Inc.and Explorer Pipeline Company filed applications for rehearing with the MPSCregarding this order. On August 12, 2008, the MPSC issued its OrderGranting Expedited Treatment and Approving Compliance Tariff Sheets, effective August 23,2008, in which the MPSC approved our tariff sheets containing our base ratesfor service rendered on and after August 23, 2008, and approved our fueladjustment clause tariff sheets effective September 1, 2008. On September 3,2008, the MPSC denied all pendingapplications for rehearing.

 

On October 2, 2008, the OPC andintervenors Praxair, Inc. and Explorer Pipeline Company filed Petitions for Writ of Review with the ColeCounty Circuit Court. These actionswere consolidated into one proceeding, and briefs are currently being filedwith the Cole County Circuit Court.

 

*2006 Rate Case*

 

All pending applications forrehearing in our 2006 rate case were denied by the MPSC on November 20,2008. On December 15, 2008, the OPC filed a Petition for Writ of Reviewwith the Cole County Circuit Court regarding the MPSC’s decisions in our 2006rate case. Praxair and Explorer Pipeline filed a Petition for Writ of Review onDecember 19, 2008. These actions were consolidated into one proceeding.Briefs have been filed by all parties.

 

*Kansas*

 

The Kansas CorporationCommission (KCC) approved a Joint Stipulated Settlement Agreement on December 9,2005 effective January 4, 2006, in relation to our last Kansas rate case.Pursuant to the Agreement, we sought KCC approval of an explicit natural gashedging program in a separate docket by March 1, 2006. We requested andreceived an extension until April 1, 2006 and made this filing on March 30,2006, which was denied in a February 4, 2008 order by the KCC. As aresult, all gains or losses related to the financial instruments used to fixthe future price of natural gas will be excluded from the Energy CostAdjustment clause implemented in the last Kansas rate case and future baseelectric rates in Kansas.

 

**COMPETITION**

 

***Electric Segment***

 

*SPP-RTO*

 

On February 1, 2007,the Southwest Power Pool (SPP) regional transmission organization (RTO)launched its energy imbalance services market (EIS). In general, the SPP RTOEIS market provides real time energy for most participating members within theSPP regional footprint. Imbalance energy prices are based on market bids andstatus/availability of dispatchable generation and transmission within the SPPmarket footprint. In addition to energy imbalance service, the SPP RTO performsa real time security-constrained****economic dispatch of all generationvoluntarily offered into the EIS market to the market participants to alsoserve the native load.

 

The SPP and its members havebeen evaluating the costs and benefits on expanding the EIS market into a fullday ahead energy market with a co-optimized ancillary services market, whichwill include the consolidation of all SPP balancing authorities, includingours, into a single SPP balancing authority. On April 28, 2009, the SPPRegional State Committee (SPP RSC), whose members include state commissionersfrom our four state commissions, and the SPP Board of Directors (SPP BOD)endorsed a cost benefit report that recommended the SPP RTO move forward 

 

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withthe development of a day-ahead market with unit commitment and co-optimizedancillary services market (Day-Ahead Market) and implement the completeDay-Ahead Market as soon as practical, which is anticipated in late 2012 orearly 2013. As part of the Day-Ahead Market, the SPP RTO will create, prior toimplementation of such market, a single NERC approved balancing authority totake over balancing authority responsibilities for its members, including us,which is expected to provide operational and economic benefits for us and ourcustomers. The implementation of the Day-Ahead Market will replace the existingEIS market, which to date has, and is expected to continue to, provide benefitsfor our customers.

 

On August 15, 2008 theSPP filed with the FERC proposed revisions to its open access transmission proforma tariff (OATT) to establish a process for including a “balanced portfolio”of economic transmission upgrades in the annual SPP Transmission ExpansionPlan. The cost of such upgrades will be recovered through a regional rateallocated to SPP members based on their load ratio share within SPP’s marketarea of the balanced portfolio’s cost. On October 16, 2008, the FERCaccepted the balanced portfolio approach, which sets forth the selectionprocess of a group of projects and regional cost allocation rules based onprojected benefits and allocated costs over a ten year period. The plan will bebalanced if the portfolio is cost beneficial for each zone, including ours,within the SPP. A balanced portfolio could include projects below the 345 kvlevel (which is the bright line voltage level for projects to be included inthe portfolio) to increase benefits to a particular zone to achieve balance ofbenefits and costs over the ten year study period. On April 28, 2009, theSPP RSC and the SPP BOD approved the first set of balanced portfolio extra highvoltage transmission projects to be constructed within the SPP region. Thetransmission expansion projects, totaling over $700 million, include projectsin Missouri, Kansas, Arkansas, Oklahoma, Nebraska and Texas. We anticipate thisset of transmission expansion projects will provide long term benefits to ourcustomers. Also on April 28, 2009, the SPP RSC and BOD approved a newreport that recommends restructuring of the SPP’s regional planning processes,which would establish an integrated planning process for reliability,transmission service and economic transmission projects, based on a new set ofplanning principles that focus on the construction of a more robusttransmission system large enough in both scale and geography to provideflexibility to meet SPP members’ and customers’ future needs. We will activelyparticipate in the development of these new processes as well as costallocation and recovery issues with members, prospective customers and thestate commission representatives to the SPP RSC.

 

*FERC Market Power Order*

 

On March 3, 2005, theFERC issued an order commencing an investigation to determine if we had marketpower within our control area based on our failure to meet one of the FERC’swholesale market share screens. We filed responses to that order in May andJune 2005 and in early January 2006. On August 15, 2006, theFERC issued its order accepting Empire’s proposed mitigation to becomeeffective May 16, 2005, subject to a further compliance filing as directedin the order. Relying on a series of orders issued since March 17, 2006 inother proceedings, the FERC rejected our tariff language and directed us tofile revisions to our market-based tariff to provide that service under thetariff applies only to sales outside our control area. The FERC directed us tomake refunds, with interest, by September 15, 2006, covering over 1,000hourly 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 the FERC. The refundobligation applied to certain wholesale power sales made “inside” our servicearea at market based rates, even though consumption of the energy occurredoutside our service area. In response to the order, we filed a Motion ForExtension of time and expedited treatment regarding the refund and requestedthat such refund be delayed until 15 days after the FERC’s order on ourrehearing request. On September 5, 2006, the FERC granted the Motion ForExtension, as requested.

 

On September 14, 2006,we filed a Request For Rehearing of the FERC’s August 15, 2006 orderregarding the refund and market power mitigation we had proposed. We requesteda rehearing and a waiver of the refund requirement in its entirety. On April 25,2008, the FERC issued an Order that rejected our Request For Rehearing,required a Compliance Filing of our market 

 

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basedrate tariff and ordered refunds with interest. We made our Compliance Filingand issued refunds totaling $340,608, including interest, on May 27, 2008.We were also required to file an informational refund report with the FERC on June 26,2008.

 

As a result of the FERC’srequirement for us to issue the aforementioned refunds and our belief that theFERC erred in its orders, on June 30, 2008 we initiated a Petition ForReview of the FERC’s orders on our market based rate refunds in the United StatesCourt of Appeals for the District of****Columbia Circuit (DC Circuit). We requestedand received approval for a consolidation of our Petition with a similarpetition by Westar Energy. Oral arguments were heard before the DC Circuit on March 26,2009. If a decision is reached in our favor, the DC Circuit will likely remandthe FERC’s orders back to the FERC for reconsideration. It is expected that thejudicial review of the Petitions will take several months.

 

*Other FERC Rulemaking*

 

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

 

**LIQUIDITY AND CAPITALRESOURCES**

 

We used approximately $41.9million of cash for capital expenditures during the first quarter of 2009 andrepaid short-term debt of $54.8 million. Our primary sources of cash flow forthese expenditures during the first quarter of 2009 were $75 million in grossproceeds from first mortgage bonds and $38.1 million in cash provided byoperating activities. As of March 31, 2009, our working capital wasnegative (current liabilities exceeded current assets), primarily due to thecontinued use of short-term debt to fund our construction program. We expect tocontinue to use short-term debt under our unsecured credit agreements. We alsohave an equity distribution program in place which is designed to provideadditional funds from the issuance of equity from time to time.

 

**Summaryof Cash Flows**

 
| ** **                               | ** ** | **Quarter Ended March 31,** | ** ** |
|------------------------------------------|------------|--------------------------------------------|------------|
| **(in millions)**                   | ** ** | **2009**                                   | ** ** | **2008** | ** ** |
| Cash provided by  (used in):             |       |                                       |       |   |   |
| Operating  activities                    |       | $                                          | 38.1       |   | $ | 32.1 |   |
| Investing  activities                    |       | (41.5                                      | )          | (61.4 | ) |
| Financing  activities                    |       | 8.7                                        |       | 29.9 |   |
| Net change in  cash and cash equivalents |       | $                                          | 5.3        |   | $ | 0.6 |   |

 

**OperatingActivities**

 

Ournet cash flows provided by continuing operating activities were $38.1 millionduring the first quarter of 2009 as compared to $32.1 million for the firstquarter of 2008. This $6 million difference was primarily due to the increasein net income and related cash effect adjustments for income taxes andderivative losses. The derivative losses were deducted from our margin account,rather than requiring additional cash outlays. Income taxes reflect a largereffect in 2009 versus 2008 for depreciation related tax deductions. In additionaccounts receivable balances increased this year over last, improving our cashposition. These positive cash effects were partially offset by the negativeeffect of decreased accounts payable, primarily related to fuel payables,reflecting a larger use of cash this year over last.

 

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**CapitalRequirements and Investing Activities**

 

Our net cash flows used ininvesting activities decreased $19.9 million during the first quarter of 2009as compared to the first quarter of 2008. The 2008 capital expenditures reflectcash outlays for the December 2008 ice storm. These expenditures wereincurred in 2008 but paid in the first quarter of 2009.

 

Our capital expenditures incurred totaled approximately $41.0 millionduring the first quarter of 2009. These capital expenditures include AFUDC,capital expenditures to retire assets and benefits from salvage. Partiallyoffsetting the capital expenditures were proceeds from the sale of landtotaling $0.4 million.

 

A breakdown of the capital expenditures for the quarter ended March 31,2009 is as follows:

 
| **(in millions)**                                       | ** ** | **Capital Expenditures** | ** ** |
|--------------------------------------------------------------|------------|-------------------------------|------------|
| Distribution and  transmission system additions              |       | $                             | 10.2       |   |
| New Generation —  Plum Point Energy Station             |       | 5.0                           |       |
| New Generation —  Iatan 2                               |       | 16.2                          |       |
| Storms                                                       |       | 0.3                           |       |
| Additions and  replacements — electric plant            |       | 8.8                           |       |
| Gas segment  additions and replacements                      |       | 0.4                           |       |
| Transportation                                               |       | 0.2                           |       |
| Other (including  retirements and salvage - net) (1)         |       | (0.7                          | )          |
| **Subtotal**                                                 |       | 40.4                          |       |
| Non-regulated  capital expenditures (primarily fiber optics) |       | 0.6                           |       |
| **Subtotal  capital expenditures incurred**(2)               |       | 41.0                          |       |
| Adjusted for  capital expenditures payable (3)               |       | 0.9                           |       |
| **Total  cash outlay**                                       |       | $                             | 41.9       |   |

 

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(1) Otherincludes equity AFUDC of $(1.4) million.

(2) Expendituresincurred represent the total cost for work completed for the projects duringthe quarter. Discussion of capital expenditures throughout this 10-Q ispresented on this basis.

(3) Theamount of expenditures paid/(unpaid) at the end of the reporting period toadjust to actual cash outlay reflected in the Investing Activities section ofthe Statement of Cash Flows.

 

Approximately 65% of ourcash requirements for capital expenditures during the first quarter of 2009were 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.

 

We estimate that internallygenerated funds will provide approximately 34% of the funds required for theremainder of our budgeted 2009 capital expenditures. We intend to utilize acombination of short-term debt, the proceeds of sales of long-term debt and/orcommon stock (including common stock sold under our Employee Stock PurchasePlan, our Dividend Reinvestment and Stock Purchase Plan, and our 401(k) Planand ESOP) to finance additional amounts needed beyond those provided byoperating activities for such capital expenditures. We will continue to utilizeshort-term debt as needed to support normal operations or other temporaryrequirements. For further information see Note 6 of “Notes to ConsolidatedFinancial Statements (Unaudited).”

 

**FinancingActivities**

 

Our net cash flows providedby financing activities decreased $21.2 million to $8.7 million in the firstquarter of 2009 as compared to $29.9 million in 2008.

 

On March 27, 2009, weissued $75 million principal amount of 7% first mortgage bonds due April 1,2024. The net proceeds (after payment of expenses) of approximately $72.7 million were used to repayshort-term debt incurred, in part, to fund our current construction program.

 

On February 25, 2009,we entered into an equity distribution agreement with UBS Securities LLC (UBS).Under the terms of the agreement, we may offer and sell shares of our commonstock, par value $1.00 per share, having an aggregate offering price of up to$60 million from time to time through UBS, as sales agent. We intend to use thenet proceeds from this equity distribution 

 

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programto repay short-term debt and for general corporate purposes, including to fundour current construction program. As of April 30, 2009, no shares havebeen sold pursuant to this program.

 

Any sales of the sharespursuant to the equity distribution agreement will be made by means of ordinarybrokers’ transactions on the New York Stock Exchange at market prices or asotherwise agreed with UBS. Under the terms of the program agreement, we mayalso sell shares to UBS as principal for UBS’ own account at a price agreedupon at the time of sale.

 

We have a $400 million shelfregistration statement with the SEC, which became effective on August 15,2008, covering our common stock, unsecured debt securities, preference stock,first mortgage bonds and trust preferred securities. As of March 31, 2009,in addition to amounts remaining under the equity distribution programdescribed above, $265 million remains available for issuance under this shelfregistration statement. Of the original $400 million, $250 million wasavailable for first mortgage bonds with $175 million remaining available afterthe issuance of $75 million in first mortgage bonds on March 27, 2009. Weplan to use a portion of the proceeds from issuances under this shelf to fund aportion of the capital expenditures for our new generation projects.

 

On March 11, 2009, weentered into a $50 million unsecured credit agreement. This agreement providesfor $50 million of revolving loans to be available to us for working capital,general corporate purposes and to back-up our use of commercial paper andterminates on July 15, 2010. This credit agreement is in addition to, andhas substantially the same covenant requirements and terms as (other thanpricing), our Amended and Restated Unsecured Credit Agreement dated March 14,2006 discussed below. There were no borrowings under this agreement at March 31,2009.

 

On July 15, 2005, weentered into a $150 million unsecured revolving credit facility until July 15,2010. Borrowings (other than through commercial paper) are at the bank’s primecommercial rate or LIBOR plus 100 basis points based on our current creditratings and the pricing schedule in the line of credit facility. On March 14,2006, we entered into the First Amended and Restated Unsecured Credit Agreementwhich amends and restates the $150 million unsecured revolving credit facility.The principal amount of the credit facility was increased to $226 million, withthe additional $76 million allocated to support a letter of credit issued inconnection with our participation in the Plum Point Energy Station project.This extra $76 million of availability reduces over a four year period in linewith the amount of construction expenditures we owe for Plum Point Unit 1 andwas $15.5 million as of May 1, 2009. The unallocated credit facility isused for working capital, general corporate purposes and to back-up our use ofcommercial paper. This facility requires our total indebtedness (which does notinclude our note payable to the securitization trust) to be less than 62.5% ofour total capitalization at the end of each fiscal quarter and our EBITDA(defined as net income plus interest, taxes, depreciation and amortization) tobe at least two times our interest charges (which includes interest on the notepayable to the securitization trust) for the trailing four fiscal quarters at theend of each fiscal quarter. Failure to maintain these ratios will result in anevent of default under the credit facility and will prohibit us from borrowingfunds thereunder. As of March 31, 2009, we are in compliance with theseratios. This credit facility is also subject to cross-default if we default onin****excess 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 $38.0 million of outstanding borrowingsunder this agreement at March 31, 2009. In addition, $9.25 million of theavailability thereunder was used at such date to back up our outstandingcommercial paper.

 

The principal amount of allseries of first mortgage bonds outstanding at any one time under the EDEMortgage is limited by terms of the mortgage to $1 billion. Substantially allof the property, plant and equipment of The Empire District Electric Company(but not its subsidiaries) is subject to the lien of the EDE Mortgage.****Restrictionsin the 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 months withinthe fifteen months preceding issuance must be two times the annual interestrequirements (as defined in the EDE Mortgage) on all first mortgage bonds thenoutstanding and on the prospective issue of new first mortgage bonds. Ourearnings for the twelve months ended March 31, 2009 would permit 

 

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usto issue approximately $242.6 million of new first mortgage bonds based on thistest with an assumed interest rate of 7.0%. In addition to the interestcoverage requirement, the EDE Mortgage provides that new bonds must be issuedagainst, among other things, retired bonds or 60% of net property additions. AtMarch 31, 2009, we had retired bonds and net property additions whichwould enable the issuance of at least $587.2 million principal amount of bondsif the annual interest requirements are met. As of March 31, 2009, we arein compliance with all restrictive covenants of the EDE Mortgage.

 

The principal amount of allseries of first mortgage bonds outstanding at any one time under the EDGMortgage is limited by terms of the mortgage to $300 million. Substantially allof 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 first mortgage bonds to be issued, the amount of suchnew first mortgage bonds shall not exceed 75% of the cost of property additionsacquired after the date of the Missouri Gas acquisition. The mortgage alsocontains a limitation on the issuance by EDG of debt (including first mortgagebonds, but excluding short-term debt incurred in the ordinary course underworking capital facilities) unless, after giving effect to such issuance, EDG’sratio of EBITDA (defined as net income plus interest, taxes, depreciation,amortization and certain other non-cash charges) to interest charges for themost recent four fiscal quarters is at least 2.0 to 1.****As of March 31, 2009, this test wouldnot allow us to issue new first mortgage bonds.

 

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

 
| ** **                                              | ** ** | **Fitch** | ** ** | **Moody’s** | ** ** | **Standard & Poor’s** | ** ** |
|---------------------------------------------------------|------------|-----------|------------|------------------|------------|------------------------------------------|------------|
| Corporate Credit  Rating                                |       | n/r*      |       | Baa2             |       | BBB-                                     |       |
| First Mortgage  Bonds                                   |       | BBB+      |       | Baa1             |       | BBB+                                     |       |
| First Mortgage  Bonds — Pollution Control Series** |       | AAA       |       | Aaa              |       | AAA                                      |       |
| Senior Notes                                            |       | BBB       |       | Baa2             |       | BBB-                                     |       |
| Trust Preferred  Securities                             |       | BBB-      |       | Baa3             |       | BB                                       |       |
| Commercial Paper                                        |       | F2        |       | P-2              |       | A-3                                      |       |
| Outlook                                                 |       | Negative  |       | Negative         |       | Stable                                   |       |

 

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*Notrated

**Insuredby a third party insurer.

 

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

 

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

 

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On December 19, 2005,Fitch Ratings initiated coverage and assigned ratings (see table above) with astable rating outlook. Fitch announced that their ratings reflect our lowbusiness risk position as a regulated electric utility, a stable serviceterritory and a seemingly improving regulatory environment in Missouri where wereceive approximately 89% of our electric revenues. On January 25, 2008,Fitch affirmed our ratings but revised their rating outlook to negative. At thetime of the change, the negative rating outlook reflected uncertaintysurrounding the outcome of our Missouri rate filing and weakness in ourprojected financial measures relative to Fitch guidelines. Events leading tothe revision were storm damage incurred in December 2007 and the extendedAsbury coal plant outage we experienced from December 2007 to February 2008.On March 9, 2009, Fitch affirmed our ratings with a negative outlook.

 

**CONTRACTUAL OBLIGATIONS**

 

Our contractual obligations have notsignificantly changed at March 31, 2009, compared to December 31,2008 other than the $75 million principal amount of 7% first mortgage bondsissued on March 27, 2009 and due April 1, 2024 and related interestcosts.

 

**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, 2009 our retained earnings balance was $13.6 million,compared to $13.4 million as of March 31, 2008, after paying out $10.9million in dividends during the first quarter of 2009. A reduction of ourdividend per share, partially or in whole, could have an adverse effect on ourcommon stock price. On April 23, 2009, the Board of Directors declared aquarterly dividend of $0.32 per share on common stock payable June 15, 2009 toholders of record as of June 1, 2009.

 

Our diluted earnings pershare were $0.32 for the quarter ended March 31, 2009 and were $1.17 and$1.09 for the years ended December 31, 2008 and 2007, respectively.Dividends paid per share were $0.32 for the three months ended March 31,2009 and $1.28 for each of the years ended December 31, 2008 and 2007.

 

In addition, the EDEMortgage and our Restated Articles contain certain dividend restrictions. Themost restrictive of these is contained in the EDE Mortgage, which provides thatwe may not declare or pay any dividends (other than dividends payable in sharesof our common stock) or make any other distribution on, or purchase (other thanwith the proceeds of additional common stock financing) any shares of, ourcommon stock if the cumulative aggregate amount thereof after August 31,1944 (exclusive of the first quarterly dividend of $98,000 paid after saiddate) would exceed the sum of $10.75 million and the earned surplus (as definedin the EDE Mortgage) accumulated subsequent to August 31, 1944, or thedate of succession in the event that another corporation succeeds to our rightsand liabilities by a merger or consolidation. On March 11, 2008, weamended the EDE Mortgage in order to provide us with more flexibility to paydividends to our shareholders by increasing the basket available to paydividends by $10.75 million, as described above. As of March 31, 2009,this restriction did not prevent us from issuing dividends.

 

In addition, under certaincircumstances, our Junior Subordinated Debentures, 8-1/2% Series due 2031,reflected as a note payable to securitization trust on our balance sheet, heldby Empire District Electric Trust I, an unconsolidated securitization trustsubsidiary, may also restrict our ability to pay dividends on our common stock.These restrictions apply if: (1) we have knowledge that an event hasoccurred that would constitute an event of default under the indenturegoverning these junior subordinated debentures and we have not taken reasonablesteps to cure the event, (2) we are in default with respect to payment of anyobligations under our guarantee relating to the underlying preferredsecurities, or (3) we have deferred interest payments on the JuniorSubordinated Debentures, 8-1/2% Series due 2031 or given notice of adeferral of interest payments. As of March 31, 2008, there were no suchrestrictions on our ability to pay dividends.

 

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**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 infinancial condition, revenues or expenses, results of operations, liquidity,capital expenditures or capital resources, other than operating leases enteredinto in the normal course of business.

 

**CRITICAL ACCOUNTING POLICIES**

 

*Goodwill.**        *We recordedgoodwill of $39.5 million upon the completion of the 2006 Missouri Gasacquisition. Goodwill represents the excess of the cost of the acquisition overthe fair value of the related net assets at the date of acquisition. Inaccordance with Statement of Financial Accounting Standards No. 142, “Goodwilland Other Intangible Assets,” (FAS 142) goodwill is required to be tested forimpairment on an annual basis or whenever events or circumstances indicatepossible impairment. In performing impairment tests, we utilize valuationtechniques which estimate the discounted future cash flows of operations. Ourprocedures include developing a baseline test and performing sensitivityanalysis to calculate a reasonable valuation range. The sensitivities arederived from altering those assumptions which are subjective in nature andinherent to a discounted cash flows valuation technique. Other qualitativefactors and comparisons to industry peers are also used to further support theassumptions and ultimately the overall evaluation. A significant qualitativefactor considered in our evaluation is the impact of regulation, including rateregulation and cost recovery for our gas segment. Some of the more significantquantitative assumptions included in our tests involve: regulatory rate designand results; the discount rate; the growth rate; capital spending rates andterminal value calculations. Risks and uncertainties affecting theseassumptions include:  management’sidentification of impairment indicators, changes in business, industry, laws,technology or economic and market conditions. While management believes theassumptions utilized in our analysis were reasonable, significant adversedevelopments in the gas segment in future periods or changes in the assumptionscould negatively impact goodwill impairment considerations, which couldadversely impact earnings. We performed our annual goodwill impairment test asof November 30, 2008 and concluded our goodwill was not impaired. Thistest estimated the fair market value of our gas segment to be 10-15% higherthan its carrying value. We do not believe the fair value of our gas segment declinedbelow the carrying value during the quarter ended March 31, 2009 and as aresult an interim test for impairment was not performed.

 

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 31,2008 for a discussion of additional critical accounting policies. There were nochanges in these policies in the quarter ended March 31, 2009.

 

**RECENTLY ISSUED ACCOUNTING STANDARDS**

 

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

 

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

 

Ourfuel procurement activities involve primary market risk exposures, includingcommodity price risk and credit risk. Commodity price risk is the potentialadverse price impact related to the fuel procurement for our generating units.Credit risk is the potential adverse financial impact resulting fromnon-performance by a counterparty of its contractual obligations. Additionally,we are exposed to interest rate risk which is the potential adverse financialimpact related to changes in interest rates.

 

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*Market Risk and Hedging Activities.*

 

Weengage in physical and financial trading activities with the goals of reducingrisk from market fluctuations. In accordance with our established Energy RiskManagement Policy, which typically includes entering into various derivativetransactions, we attempt to mitigate our commodity market risk. Derivatives areutilized to manage our gas commodity market risk and to help manage ourexposure resulting from purchasing most of our natural gas on the volatile spotmarket for the generation of power for our native-load customers. See Note 4 of“Notes to Consolidated Financial Statements (Unaudited)” for furtherinformation.

 

*Commodity Price Risk*.

 

Weare exposed to the impact of market fluctuations in the price and transportationcosts of coal, natural gas, and electricity and employ established policies andprocedures to manage the risks associated with these market fluctuations,including utilizing derivatives.

 

We satisfied 60.9% of our2008 generation fuel supply need through coal. Approximately 90% of our 2008coal supply was Western coal. We have contracts and binding proposals to supplyfuel for our coal plants through 2013. These contracts and binding proposalssatisfy approximately 89% of our anticipated fuel requirements for 2009, 75%for 2010, 58% for 2011, 27% for 2012 and 30% of our 2013 requirements for ourAsbury and Riverton coal plants. In order to manage our exposure to fuelprices, future coal supplies will be acquired using a combination of short-termand long-term contracts.

 

We are exposed to changes inmarket prices for natural gas we must purchase to run our combustion turbinegenerators. Our natural gas procurement program is designed to manage our coststo avoid volatile natural gas prices. We enter into physical forward andfinancial derivative contracts with counterparties relating to our futurenatural gas requirements that lock in prices (with respect to predeterminedpercentages of our expected future natural gas needs) in an attempt to lessen thevolatility in our fuel expenditures and improve predictability. As of April 24,2009, 87%, or 5.3 million Dths’s, of our anticipated volume of natural gasusage for our electric operations for the remainder of 2009 is hedged.

 

Based on our expected naturalgas purchases for our electric operations for the next twelve months, ifaverage natural gas prices should increase 10% more than the price at March 31,2009, our natural gas cost would increase by approximately $1.3 million basedon our March 31, 2009 total hedged positions for the next twelve months.However, this is probable of recovery through fuel adjustment mechanisms.

 

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 April 24, 2009, we have 0.4 million Dths in storage onthe three pipelines that serve our customers. This represents 19% of ourstorage capacity. Our long-term hedgestrategy is to mitigate price volatility for our customers by hedging a minimumof 50% of current year, up to 50% of the second year and up to 20% of thirdyear expected gas usage by the beginning of the ACA year at September 1. However, dueto purchased natural gas cost recovery mechanisms for our retail customers,fluctuations in the cost of natural gas have little effect on income.

 

*CreditRisk*.

 

In order to minimize overallcredit risk, we maintain credit policies, including the evaluation ofcounterparty financial condition and the use of standardized agreements thatfacilitate the netting of cash flows associated with a single counterparty. SeeNote 4 of “Notes to Consolidated Financial Statements (Unaudited)” regardingagreements containing credit risk contingent features. In addition, certaincounterparties make available collateral in the form of cash held as margindeposits as a result of exceeding agreed-upon credit exposure thresholds or maybe required to prepay the transaction. Conversely, we are required to postcollateral with counterparties at certain thresholds, which is typically theresult of changes in commodity prices. Amounts reported as margin depositliabilities represent counterparty funds we hold that result from varioustrading counterparties exceeding agreed-upon credit exposure thresholds.Amounts reported as margin deposit assets represent our funds held on depositby various trading counterparties that resulted from us exceeding agreed-uponcredit limits established by the counterparties. The following table depictsour margin deposit assets and margin deposit liabilities at March 31, 2009and December 31, 2008:

 

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| **(in  millions)**          | ** ** | **March 31,  2009** | ** ** | **December 31,  2008** | ** ** |
|-----------------------------|------------|--------------------------|------------|-----------------------------|------------|
|                        |       |                     |       |                        |       |
| Margin deposit  assets      |       | $                        | 7.5        |                        | $          | 10.7 |   |
| Margin deposit  liabilities |       | $                        | —     |                        | $          | — |   |

 

Our exposure to credit riskis concentrated primarily within our fuel procurement process, as we transactwith a smaller, less diverse group of counterparties and transactions mayinvolve large notional volumes and potentially volatile commodity prices. At April 24,2009, our net credit exposure totaled ($21.5) million reflecting that ourcounterparties are exposed to Empire for the net unrealized mark-to-marketlosses for physical forward and financial natural gas contracts carried at fairvalue. This $21.5 million consists of $11.9 million of net unrealizedmark-to-market losses for physical forward natural gas contracts and $9.6 millionof net unrealized mark-to-market losses for financial natural gas contracts.Included in the $9.6 million net unrealized mark-to-market losses for financialnatural gas contracts and partially offsetting the $11.5 million of exposure ofcounterparties to Empire is exposure to a single counterparty of $1.9 millionof unrealized mark-to-market gains. We are holding no collateral from thiscounterparty since we are below the $10 million mark-to-market collateralthreshold in our agreement with this counterparty. As noted above, we have $7.5million on deposit with NYMEX covering counterparty exposure to Empire. In addition, if NYMEX gas prices decreased25% from their April 24, 2009 levels, we would be required to post anadditional $2.0 million in collateral. If these prices increased 25%, ourcollateral requirement would decrease $1.5 million.

 

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.

 

*Interest Rate Risk.*

 

Weare exposed to changes in interest rates as a result of financing through ourissuance of commercial paper and other short-term debt. We manage our interestrate exposure by limiting our variable-rate exposure (applicable to commercialpaper and borrowings under our unsecured credit agreement) to a certainpercentage of total capitalization, as set by policy, and by monitoring theeffects of market changes in interest rates.

 

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

 

**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, 2009.

 

There have been no changes in our internal control over financialreporting that occurred during the first quarter of 2009 that have materiallyaffected, or are reasonably likely to materially affect, our internal controlover financial reporting.

 

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**PART II.  OTHER INFORMATION**

 

**Item 1A.  Risk Factors.**

 

The following risk factors update and replace in their entirety therisk factors set forth in our Annual Report on Form 10-K for the yearended December 31, 2008.

 

**Anyreduction in our credit ratings could materially and adversely affect ourbusiness, financial condition and results of operations.**

 

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

 
| ** **                                                  | ** ** | **Fitch** | ** ** | **Moody’s** | ** ** | **Standard &  Poor’s** |
|-------------------------------------------------------------|------------|-----------|------------|------------------|------------|--------------------------------------|
| Corporate  Credit Rating                                    |       | n/r*      |       | Baa2             |       | BBB-                                 |
| EDE  First Mortgage Bonds                                   |       | BBB+      |       | Baa1             |       | BBB+                                 |
| EDE  First Mortgage Bonds — Pollution Control Series** |       | AAA       |       | Aaa              |       | AAA                                  |
| Senior  Notes                                               |       | BBB       |       | Baa2             |       | BBB-                                 |
| Trust  Preferred Securities                                 |       | BBB-      |       | Baa3             |       | BB                                   |
| Commercial  Paper                                           |       | F2        |       | P-2              |       | A-3                                  |
| Outlook                                                     |       | Negative  |       | Negative         |       | Stable                               |

 

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*Notrated.

**Insuredby a third party insurer.

 

The ratings indicate theagencies’ assessment of our ability to pay interest, distributions andprincipal on these securities. A rating is not a recommendation to purchase,sell or hold securities and each rating should be evaluated independently ofany other rating. The lower the rating, the higher the interest cost of thesecurities when they are sold. In addition, a downgrade in our senior unsecuredlong-term debt rating would result in an increase in our borrowing costs underour bank credit facility. If any of our ratings fall below investment grade(investment grade is defined as Baa3 or above for Moody’s and BBB- or above forStandard & Poor’s and Fitch), our ability to issue short-term debt,commercial paper or other securities or to market those securities would beimpaired or made more difficult or expensive. Therefore, any such downgradescould have a material adverse effect on our business, financial condition andresults of operations. In addition, any actual downgrade of our commercialpaper rating from Moody’s or Fitch, 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 ourrevolving credit facilities, which may result in higher costs.

 

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

 

**Financialmarket disruptions may increase financing costs, limit access to the creditmarkets or cause reductions in investment values in our pension plan assets.**

 

The recent general marketdeclines resulting in part from the sub-prime mortgage issues have generallyreduced access to the capital markets and reduced market returns oninvestments. We estimate our capital expenditures to be $168.9 million in 2009.Although we believe it is unlikely we will have difficulty accessing themarkets for the capital needed to complete these projects, our financing costswill likely be higher when compared to previous years. The market’s effect onour pension plan assets resulted in a negative return of 25.1% in 2008. Thisdecline will likely result in increased funding requirements under the PensionProtection Act of 2006.

 

**We areexposed to factors that can increase our fuel and purchased power expenditures,including disruption in deliveries of coal or natural gas, decreased outputfrom our power plants, failure of performance by purchased power counterpartiesand market risk in our fuel procurement strategy.**

 

Fuel and purchased powercosts are our largest expenditures. Increases in the price of coal, natural gasor the cost of purchased power will result in increased electric operatingexpenditures.

 

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We depend upon regular deliveriesof coal as fuel for our Riverton, Asbury and Iatan plants, and as fuel for thefacility which supplies us with purchased power under our contract with WestarEnergy. Substantially all of this coal comes from mines in the Powder RiverBasin of Wyoming and is delivered to the plants by train. Production problemsin these mines, railroad transportation or congestion problems, such as thosethat occurred in 2005 and 2006, or unavailability of trains could affectdelivery cycle times required to maintain plant inventory levels, causing us toimplement coal conservation and supply replacement measures to retain adequatereserve inventories at our facilities. These measures could include some or allof the following:  reducing the output ofour coal plants, increasing the utilization of our higher-cost gas-firedgeneration facilities, purchasing power from other suppliers, adding additionalleased trains to our supply system and purchasing locally mined coal which canbe delivered without using the railroads. Such measures could result inincreased fuel and purchased power expenditures.

 

With the addition of theMissouri fuel adjustment mechanism effective September 1, 2008, we nowhave a fuel cost recovery mechanism in all of our jurisdictions, which significantlyreduces our net income exposure to the impact of the risks discussed above.However, cash flow could still be impacted by these increased expenditures. Weare also subject to prudency reviews which could negatively impact our netincome if a regulatory commission would conclude our costs were incurredimprudently.

 

We have also established arisk management practice of purchasing contracts for future fuel needs to meetunderlying customer needs and manage cost and pricing uncertainty. Within thisactivity, we may incur losses from these contracts. By using physical andfinancial instruments, we are exposed to credit risk and market risk. Marketrisk is the exposure to a change in the value of commodities caused byfluctuations in market variables, such as price. The fair value of derivativefinancial instruments we hold is adjusted cumulatively on a monthly basis untilprescribed determination periods. At the end of each determination period,which is the last day of each calendar month in the period, any realized gainor loss for that period related to the contract will be reclassified to fuelexpense and recovered or refunded to the customer through our fuel adjustmentmechanisms. Credit risk is the risk that the counterparty might fail to fulfillits obligations under contractual terms.

 

**We aresubject to regulation in the jurisdictions in which we operate.**

 

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

 

The FERC has jurisdictionover wholesale rates for electric transmission service and electric energy soldin interstate commerce. Federal, state and local agencies also havejurisdiction over many of our other activities.

 

Information concerningrecent filings requesting increases in rates and related matters is set forthunder Item 7, “Management’s Discussion and Analysis of Financial Condition andResults of Operations — Rate Matters.”

 

We are unable to predict theimpact on our operating results from the regulatory activities of any of theseagencies. Despite our requests, these regulatory commissions have solediscretion to leave rates unchanged, grant increases or order decreases in thebase rates we charge our utility customers. They have similar authority withrespect to our recovery of increases in our fuel and purchased power costs. Ifour costs increase and we are unable to recover increased costs through baserates or fuel adjustment clauses, or if we are unable to fully recover ourinvestments in new facilities, our results of operations could be materiallyadversely affected. Changes in regulations or the imposition of additionalregulations could also have a material adverse effect on our results ofoperations.

 

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**Operations risks may adversely affect our business andfinancial results.**

 

The operation of ourelectric generation, and electric and gas transmission and distribution systemsinvolves many risks, including breakdown or failure of expensive andsophisticated equipment, processes and personnel performance; operatinglimitations that may be imposed by equipment conditions, environmental or otherregulatory requirements; fuel supply or fuel transportation reductions orinterruptions; transmission scheduling constraints; and catastrophic eventssuch as fires, explosions, severe weather or other similar occurrences.

 

We have implementedtraining, preventive maintenance and other programs, but there is no assurancethat these programs will prevent or minimize future breakdowns, outages orfailures of our generation facilities. In those cases, we would need to eitherproduce replacement power from our other facilities or purchase power fromother suppliers at potentially volatile and higher cost in order to meet oursales obligations.

 

These and other operatingevents may reduce our revenues, increase costs, or both, and may materiallyaffect our results of operations, financial position and cash flows.

 

**We areexposed to increases in costs and reductions in revenue which we cannot controland which may adversely affect our business, financial condition and results ofoperations.**

 

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

 

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

 

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. Because natural gas is heavily used for residentialand commercial heating, the demand for this product depends heavily uponweather patterns throughout our natural gas service territory and a significantamount of our natural gas revenues are recognized in the first and fourthquarters related to the heating seasons. Accordingly, our natural gasoperations have historically generated less revenues and income when weatherconditions are warmer in the winter.

 

Theprimary driver of our gas operating expense in any period is the price ofnatural gas.

 

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

 

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

 

In our natural gas utilitybusiness, we are permitted to recover the cost of gas directly from ourcustomers through the use of a purchased gas adjustment provision. Ourpurchased gas adjustment provision is regularly reviewed by the Missouri PublicService Commission (MPSC). In addition to reviewing our adjustments to customerrates, the MPSC reviews our costs for prudency as well. To the extent the MPSCmay determine certain costs were not incurred prudently, it could adverselyaffect our gas segment earnings and cash flows. In addition, increases innatural gas costs affect total prices to our customers and, therefore, thecompetitive position of gas relative to electricity and other forms of energy.Increases in natural gas costs may also result in lower usage 

 

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bycustomers unable to switch to alternate fuels. Such disallowed costs orcustomer losses could have a material adverse effect on our business, financialcondition and results of operations.

 

**We aresubject to environmental laws and the incurrence of environmental liabilitieswhich may adversely affect our business, financial condition and results ofoperations.**

 

We are subject to extensivefederal, state and local regulation with regard to air and other environmentalmatters. Failure to comply with these laws and regulations could have amaterial adverse effect on our results of operations and financial position. Inaddition, new environmental laws and regulations, and new interpretations ofexisting environmental laws and regulations, have been adopted and may in thefuture be adopted which may substantially increase our future environmentalexpenditures for both new facilities and our existing facilities. Compliancewith current and future air emission standards (such as those limiting emissionlevels of sulfur dioxide (SO2) and nitrogen oxide (NOx) and, potentially,carbon dioxide (CO2)) has required, and may in the future require, significantenvironmental expenditures. Although we generally recover such costs throughour rates, there can be no assurance that we will recover all, or any part of,such increased costs in future rate cases. The incurrence of additionalmaterial environmental costs which are not recovered in our rates may result ina material adverse effect on our business, financial condition and results ofoperations.

 

**Thecost and schedule of construction projects may materially change.**

 

We have entered intocontracts to purchase an undivided interest in 50 megawatts (7.5% ownershipinterest) of the Plum Point Energy Station’s new 665-megawatt, coal-firedgenerating facility which is being built near Osceola, Arkansas. We have alsoentered into an agreement with Kansas City Power & Light Company to purchasean undivided ownership interest in the coal-fired Iatan 2 generating facility.We will own 12%, or approximately 100 megawatts, of the 850-megawatt unit.

 

There are risks that actualcosts may exceed budget estimates, delays may occur in obtaining permits andmaterials, suppliers and contractors may not perform as required under theircontracts, there may be inadequate availability or productivity or increasedcost of qualified craft labor, start-up activities may take longer thancurrently planned, the scope and timing of projects may change, and otherevents beyond our control, including the failure of one or more of thegeneration plant co-owners to pay their share of construction, operations andmaintenance costs, may occur that may materially affect the schedule, budget,cost and performance of these projects.

 

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

 

(a)                                  The AnnualMeeting of Stockholders was held on April 23, 2009.

 

(b)                                 The followingpersons were re-elected Directors of Empire to serve until the 2012 AnnualMeeting of Stockholders:

 

B. Thomas Mueller (28,855,278 votes for; 527,446 withheld authority).

 

D. Randy Laney (28,817,587 votes for; 565,137 withheld authority).

 

The following persons were elected Directors of Empire to serve untilthe 2012 Annual Meeting of Stockholders:

 

Bonnie C. Lind (28,792,170 votes for; 590,554 withheld authority).

 

Paul R. Portney (28,759,326 votes for; 623,398 withheld authority).

 

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The term of office as Director of the following other Directorscontinued after the meeting:   William L.Gipson, Kenneth R. Allen, Bill D. Helton, Ross C. Hartley, Julio S. Leon, andAllan 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, 2009. Passage of the proposalrequired the affirmative vote of a majority of the votes cast. The proposalreceived 28,945,310 votes for and 359,096 votes against.

 

**Item5.  Other Information.**

 

Forthe twelve months ended March 31, 2009, our ratio of earnings to fixedcharges was 2.26x.  See Exhibit (12)hereto.

 

**Item 6.  Exhibits.**

 

(a)                                 Exhibits.

 

(10)(a) Thirty-fourthSupplemental Indenture, dated March 27, 2009, to the Indenture of Mortgageand Deed of Trust dated as of September 1, 1944, as amended and supplemented,among the Company, The Bank of New York Mellon Trust Company, N.A. and UMB Bank &Trust, N.A. (Incorporated by reference to Exhibit 10.1 to Current Reporton Form 8-K dated March 27, 2009 and filed March 30, 2009, File No. 1-3368).

 

(10)(b) EquityDistribution Agreement dated February 25, 2009 between The Empire DistrictElectric Company and UBS Securities LLC (Incorporated by reference to Exhibit 10.1to Current Report on Form 8-K dated February 25, 2009 and filed February 26,2009, File No. 1-3368).

 

(10)(c) UnsecuredCredit Agreement dated as of March 11, 2009, among The Empire DistrictElectric Company, UMB Bank, N.A. as administrative agent, Bank of America,N.A., as syndication agent, Wells Fargo Bank, N.A., as documentation agent, andthe lenders named therein (Incorporated by reference to Exhibit 10.1 toCurrent Report on Form 8-K dated March 11, 2009 and filed March 12,2009, File No. 1-3368).

 

(12)Computation of Ratio of Earnings to FixedCharges.

 

(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 7,  2009 |                                      |   |

 

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