Tableof Contents

 

 

 

**UNITED STATESSECURITIES AND EXCHANGE COMMISSION**

**WASHINGTON,D.C. 20549**

 

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**FORM 10-Q**

 

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**(Mark One)**

 

**x****      Quarterlyreport pursuant to Section 13 or 15(d) of the Securities Exchange Actof 1934**

 

**For the quarterly period ended March 31, 2010**

** **

**or**

 

**o****         Transitionreport pursuant to Section 13 or 15(d) of the Securities Exchange Actof 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 **x**  No o

 

Indicate by check mark whether the registrant has submittedelectronically and posted on its corporate Web site, if any, every InteractiveData File required to be submitted and posted pursuant to Rule 405 ofRegulation S-T (§232.405 of this chapter) during the preceding 12 months (orfor such shorter period that the registrant was required to submit and postsuch files).  Yes o  No 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 o  No **x**

 

As of May 1,2010, 40,142,184 shares of common stock were outstanding.

 

 

 

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Table of Contents

 

**THEEMPIRE DISTRICT ELECTRIC COMPANY**

 

**INDEX**

 
| ** **     | ** ** | ** **                                                                                  | ** **                                       | **PAGE** |
|----------------|------------|---------------------------------------------------------------------------------------------|--------------------------------------------------|----------|
|           |       |                                                                                        |                                             |     |
|           |       | Forward  Looking Statements                                                                 |                                             | 3        |
|           |       |                                                                                        |                                             |     |
| Part I -  |       | Financial Information:                                                                      |                                             | 4        |
|           |       |                                                                                        |                                             |     |
| Item 1.        |       | Financial Statements:                                                                       |                                             |     |
|           |       |                                                                                        |                                             |     |
|           |       | a.                                                                                          | Consolidated Statements of  Income               |     | 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 |                                             | 30       |
|           |       |                                                                                        |                                             |     |
|           |       | Executive  Summary                                                                          |                                             | 30       |
|           |       |                                                                                        |                                             |     |
|           |       | Results  of Operations                                                                      |                                             | 34       |
|           |       |                                                                                        |                                             |     |
|           |       | Rate Matters                                                                                |                                             | 42       |
|           |       |                                                                                        |                                             |     |
|           |       | Competition                                                                                 |                                             | 45       |
|           |       |                                                                                        |                                             |     |
|           |       | Liquidity and Capital Resources                                                             |                                             | 47       |
|           |       |                                                                                        |                                             |     |
|           |       | Contractual  Obligations                                                                    |                                             | 51       |
|           |       |                                                                                        |                                             |     |
|           |       | Dividends                                                                                   |                                             | 51       |
|           |       |                                                                                        |                                             |     |
|           |       | Off-Balance  Sheet Arrangements                                                             |                                             | 52       |
|           |       |                                                                                        |                                             |     |
|           |       | Critical  Accounting Policies                                                               |                                             | 52       |
|           |       |                                                                                        |                                             |     |
|           |       | Recently Issued Accounting Standards                                                        |                                             | 52       |
|           |       |                                                                                        |                                             |     |
| Item 3.        |       | Quantitative  and Qualitative Disclosures About Market Risk                                 |                                             | 52       |
|           |       |                                                                                        |                                             |     |
| Item 4.        |       | Controls and  Procedures                                                                    |                                             | 55       |
|           |       |                                                                                        |                                             |     |
| Part II - |       | Other Information:                                                                          |                                             |     |
|           |       |                                                                                        |                                             |     |
| Item 1.        |       | Legal Proceedings                                                                           |                                             | 55       |
|           |       |                                                                                        |                                             |     |
| Item 1A.       |       | Risk Factors                                                                                |                                             | 55       |
|           |       |                                                                                        |                                             |     |
| Item  2.       |       | Unregistered  Sales of Equity Securities and Use of Proceeds - (none)                       |                                             |     |
|           |       |                                                                                        |                                             |     |
| Item  3.       |       | Defaults  Upon Senior Securities - (none)                                                   |                                             |     |
|           |       |                                                                                        |                                             |     |
| Item 5.        |       | Other Information                                                                           |                                             | 55       |
|           |       |                                                                                        |                                             |     |
| Item 6.        |       | Exhibits                                                                                    |                                             | 55       |
|           |       |                                                                                        |                                             |     |
|           |       | Signatures                                                                                  |                                             | 56       |

 

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**FORWARD LOOKING STATEMENTS**

 

Certain matters discussedin this quarterly report are “forward-looking statements” intended to qualifyfor the safe harbor from liability established by the Private SecuritiesLitigation Reform Act of 1995. Such statements address or may address futureplans, objectives, expectations and events or conditions concerning variousmatters such as capital expenditures, earnings, pension and other costs,competition, litigation, our construction program, our generation plans, ourfinancing plans, potential acquisitions, rate and other regulatory matters,liquidity and capital resources and accounting matters. Forward-lookingstatements may contain words like “anticipate”, “believe”, “expect”, “project”,“objective” or similar expressions to identify them as forward-lookingstatements. Factors that could cause actual results to differ materially fromthose currently anticipated in such statements include:

 

·                  weather, business and economic conditionsand other factors which may impact sales volumes and customer growth;

·                  the amount, terms and timing of raterelief we seek and related matters;

·                  the cost and availability of purchasedpower and fuel, and the results of our activities (such as hedging) to reducethe volatility of such costs;

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

·                  the results of prudency and similarreviews by regulators of costs we incur, including capital expenditures;

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

·                  the costs and other impacts resultingfrom natural disasters, such as tornados and ice storms;

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

·                  legislation;

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

·                  competition, including the regional SPPenergy imbalance market;

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

·                  the impact of electric deregulation onoff-system sales;

·                  changes in accounting requirements;

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

·                  rate regulation, growth rates, discountrates, capital spending rates, terminal value calculations and other factorsintegral to the calculations utilized to test the impairment of goodwill, inaddition to market and economic conditions which could adversely affect theanalysis and ultimately negatively impact earnings;

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

·                  the performance of our pension assets andother post employment benefit plan assets and the resulting impact on ourrelated funding commitments;

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

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

·                  costs and effects of legal andadministrative proceedings, settlements, investigations and claims;

·                  our exposure to the credit risk of ourhedging counterparties; and

·                  other circumstances affecting anticipatedrates, revenues and costs.

 

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

 

We caution you that anyforward-looking statements are not guarantees of future performance and involveknown and unknown risk, uncertainties and other factors which may cause ouractual results, performance or achievements to differ materially from thefacts, results, performance or achievements we have anticipated in suchforward-looking statements.

 

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**PART I.  FINANCIAL INFORMATION**

 

**Item 1. Financial Statements**

 

**THEEMPIRE DISTRICT ELECTRIC COMPANY**

**CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)**

 
| ** **                                                                              | ** ** | **Three Months Ended**                     | ** ** |
|-----------------------------------------------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                                                              | ** ** | **March 31,**                         | ** ** |
| ** **                                                                              | ** ** | **2010**                                   | ** ** | **2009** | ** ** |
| ** **                                                                              | ** ** | **(000’s except per share  amounts)** | ** ** |
| **Operating revenues:**                                                                 | ** ** | ** **                                 |       |   |   |
| Electric                                                                                |       | $                                          | 113,600    |   | $ | 106,363 |   |
| Gas                                                                                     |       | 24,560                                     |       | 28,087 |   |
| Water                                                                                   |       | 433                                        |       | 424 |   |
| Other                                                                                   |       | 1,300                                      |       | 1,141 |   |
|                                                                                    |       | 139,893                                    |       | 136,015 |   |
| **Operating revenue deductions:**                                                       |       |                                       |       |   |   |
| Fuel  and purchased power                                                               |       | 50,684                                     |       | 46,790 |   |
| Cost  of natural gas sold and transported                                               |       | 15,109                                     |       | 19,308 |   |
| Regulated  operating expenses                                                           |       | 18,917                                     |       | 17,502 |   |
| Other  operating expenses                                                               |       | 488                                        |       | 409 |   |
| Maintenance  and repairs                                                                |       | 7,807                                      |       | 7,667 |   |
| Depreciation  and amortization                                                          |       | 13,185                                     |       | 12,673 |   |
| Provision  for income taxes                                                             |       | 9,889                                      |       | 5,533 |   |
| Other  taxes                                                                            |       | 7,736                                      |       | 7,478 |   |
|                                                                                    |       | 123,815                                    |       | 117,360 |   |
|                                                                                    |       |                                       |       |   |   |
| **Operating income**                                                                    |       | 16,078                                     |       | 18,655 |   |
| ** **                                                                              |       |                                       |       |   |   |
| **Other income and (deductions):**                                                      |       |                                       |       |   |   |
| Allowance  for equity funds used during construction                                    |       | 1,741                                      |       | 1,407 |   |
| Interest  income                                                                        |       | 70                                         |       | 77 |   |
| Provision  for other income taxes                                                       |       | (46                                        | )          | (76 | ) |
| Other,  net                                                                             |       | (247                                       | )          | 78 |   |
|                                                                                    |       | 1,518                                      |       | 1,486 |   |
| **Interest charges:**                                                                   |       |                                       |       |   |   |
| Long-term  debt                                                                         |       | 10,484                                     |       | 9,634 |   |
| Trust  preferred securities                                                             |       | 1,063                                      |       | 1,063 |   |
| Short-term  debt                                                                        |       | 245                                        |       | 580 |   |
| Allowance  for borrowed funds used during construction                                  |       | (2,414                                     | )          | (2,196 | ) |
| Other                                                                                   |       | (368                                       | )          | 147 |   |
|                                                                                    |       | 9,010                                      |       | 9,228 |   |
| **Net income**                                                                          |       | $                                          | 8,586      |   | $ | 10,913 |   |
| ** **                                                                              |       |                                       |       |   |   |
| Weighted  average number of common shares outstanding - basic                           |       | 38,601                                     |       | 34,064 |   |
|                                                                                    |       |                                       |       |   |   |
| Weighted  average number of common shares outstanding - diluted                         |       | 38,646                                     |       | 34,098 |   |
|                                                                                    |       |                                       |       |   |   |
| **Total earnings per weighted average share of  common stock — basic and diluted** | ** ** | **$**                                      | **0.22**   |   | $ | 0.32 |   |
| ** **                                                                              | ** ** | ** **                                 |       |   |   |
| **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 INCOME (UNAUDITED)**

 
| ** **                                                                              | ** ** | **Twelve Months Ended**                    | ** ** |
|-----------------------------------------------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                                                              | ** ** | **March 31,**                         | ** ** |
| ** **                                                                              | ** ** | **2010**                                   | ** ** | **2009** | ** ** |
| ** **                                                                              | ** ** | **(000’s except per share  amounts)** | ** ** |
| **Operating revenues:**                                                                 | ** ** | ** **                                 |       |   |   |
| Electric                                                                                |       | $                                          | 440,370    |   | $ | 444,524 |   |
| Gas                                                                                     |       | 53,787                                     |       | 66,250 |   |
| Water                                                                                   |       | 1,772                                      |       | 1,770 |   |
| Other                                                                                   |       | 5,117                                      |       | 4,688 |   |
|                                                                                    |       | 501,046                                    |       | 517,232 |   |
| **Operating revenue deductions:**                                                       |       |                                       |       |   |   |
| Fuel  and purchased power                                                               |       | 185,922                                    |       | 193,906 |   |
| Cost  of natural gas sold and transported                                               |       | 31,402                                     |       | 44,237 |   |
| Regulated  operating expenses                                                           |       | 74,502                                     |       | 71,522 |   |
| Other  operating expenses                                                               |       | 1,879                                      |       | 1,915 |   |
| Maintenance  and repairs                                                                |       | 33,152                                     |       | 30,651 |   |
| Depreciation  and amortization                                                          |       | 52,006                                     |       | 52,613 |   |
| Provision  for income taxes                                                             |       | 23,927                                     |       | 21,543 |   |
| Other  taxes                                                                            |       | 26,338                                     |       | 25,737 |   |
|                                                                                    |       | 429,128                                    |       | 442,124 |   |
|                                                                                    |       |                                       |       |   |   |
| **Operating income**                                                                    |       | 71,918                                     |       | 75,108 |   |
| ** **                                                                              |       |                                       |       |   |   |
| **Other income and (deductions):**                                                      |       |                                       |       |   |   |
| Allowance  for equity funds used during construction                                    |       | 6,542                                      |       | 6,218 |   |
| Interest  income                                                                        |       | 211                                        |       | 1,055 |   |
| Provision  for other income taxes                                                       |       | (281                                       | )          | (86 | ) |
| Other,  net                                                                             |       | (785                                       | )          | (1,254 | ) |
|                                                                                    |       | 5,687                                      |       | 5,933 |   |
| **Interest charges:**                                                                   |       |                                       |       |   |   |
| Long-term  debt                                                                         |       | 42,935                                     |       | 37,602 |   |
| Trust  preferred securities                                                             |       | 4,250                                      |       | 4,250 |   |
| Short-term  debt                                                                        |       | 790                                        |       | 1,902 |   |
| Allowance  for borrowed funds used during construction                                  |       | (8,142                                     | )          | (7,436 | ) |
| Other                                                                                   |       | (1,196                                     | )          | 1,077 |   |
|                                                                                    |       | 38,637                                     |       | 37,395 |   |
| ** **                                                                              |       |                                       |       |   |   |
| **Net income**                                                                          |       | $                                          | 38,968     |   | $ | 43,646 |   |
| ** **                                                                              |       |                                       |       |   |   |
| Weighted  average number of common shares outstanding - basic                           |       | 36,042                                     |       | 33,921 |   |
|                                                                                    |       |                                       |       |   |   |
| Weighted  average number of common shares outstanding — diluted                    |       | 36,065                                     |       | 33,960 |   |
|                                                                                    |       |                                       |       |   |   |
| **Total earnings per weighted average share of  common stock — basic and diluted** |       | $                                          | 1.08       |   | $ | 1.29 |   |
| ** **                                                                              | ** ** | ** **                                 |       |   |   |
| **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,**     | ** ** |
| ** **                                                                                                      | ** ** | **2010**               | ** ** | **2009** | ** ** |
| ** **                                                                                                      | ** ** | **($-000’s)**     | ** ** |
|                                                                                                            | ** ** | ** **             |       |   |   |
| **Net income**                                                                                                  |       | $                      | 8,586      |   | $ | 10,913 |   |
| Reclassification  adjustments for loss included in net income or reclassified to regulatory  asset or liability |       | —                 |       | 4,926 |   |
| Net  change in fair market value of open derivative contracts for period                                        |       | (6,001                 | )          | (9,333 | ) |
| Income  taxes                                                                                                   |       | 2,286                  |       | 1,679 |   |
| ** **                                                                                                      |       |                   |       |   |   |
| **Comprehensive income**                                                                                        |       | $                      | 4,871      |   | $ | 8,185 |   |

** **
| ** **                                                                                                      | ** ** | **Twelve Months Ended** | ** ** |
|-----------------------------------------------------------------------------------------------------------------|------------|-------------------------|------------|
| ** **                                                                                                      | ** ** | **March 31,**      | ** ** |
| ** **                                                                                                      | ** ** | **2010**                | ** ** | **2009** | ** ** |
| ** **                                                                                                      | ** ** | **($-000’s)**      | ** ** |
|                                                                                                            | ** ** | ** **              |       |   |   |
| **Net income**                                                                                                  |       | $                       | 38,968     |   | $ | 43,646 |   |
| Reclassification  adjustments for loss included in net income or reclassified to regulatory  asset or liability |       | 8,643                   |       | 1,913 |   |
| Net  change in fair market value of open derivative contracts for period                                        |       | (6,244                  | )          | (37,749 | ) |
| Income  taxes                                                                                                   |       | (914                    | )          | 13,653 |   |
| ** **                                                                                                      |       |                    |       |   |   |
| **Comprehensive income**                                                                                        |       | $                       | 40,453     |   | $ | 21,463 |   |

 

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

 

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**THEEMPIRE DISTRICT ELECTRIC COMPANY**

**CONSOLIDATED BALANCE SHEETS(UNAUDITED)**

 
| ** **                                            | ** ** | **March 31, 2010** | ** ** | **December 31, 2009** | ** ** |
|-------------------------------------------------------|------------|-------------------------|------------|----------------------------|------------|
| ** **                                            | ** ** | **($-000’s)**      | ** ** |
| **Assets**                                            |       |                    |       |                       |       |
| Plant and property, at original cost:                 |       |                    |       |                       |       |
| Electric                                              |       | $                       | 1,640,469  |                       | $          | 1,619,949 |   |
| Natural gas                                           |       | 58,306                  |       | 58,180                     |       |
| Water                                                 |       | 10,975                  |       | 10,891                     |       |
| Other                                                 |       | 29,646                  |       | 29,564                     |       |
| Construction work in progress                         |       | 312,847                 |       | 302,012                    |       |
|                                                  |       | 2,052,243               |       | 2,020,596                  |       |
| Accumulated depreciation and amortization             |       | 572,366                 |       | 561,586                    |       |
|                                                  |       | 1,479,877               |       | 1,459,010                  |       |
|                                                  |       |                    |       |                       |       |
| **Current assets:**                                   |       |                    |       |                       |       |
| Cash and cash equivalents                             |       | 5,977                   |       | 5,620                      |       |
| Accounts receivable — trade, net                 |       | 40,806                  |       | 36,136                     |       |
| Accrued unbilled revenues                             |       | 15,558                  |       | 23,717                     |       |
| Accounts receivable — other                      |       | 16,609                  |       | 21,417                     |       |
| Fuel, materials and supplies                          |       | 41,880                  |       | 43,973                     |       |
| Unrealized gain in fair value of derivative contracts |       | 465                     |       | 2,782                      |       |
| Prepaid expenses and other                            |       | 6,134                   |       | 4,438                      |       |
| Regulatory assets                                     |       | 3,730                   |       | 772                        |       |
|                                                  |       | 131,159                 |       | 138,855                    |       |
| **Noncurrent assets and deferred  charges:**          | ** ** | ** **              |       |                       |       |
| Regulatory assets                                     |       | 166,013                 |       | 168,254                    |       |
| Goodwill                                              |       | 39,492                  |       | 39,492                     |       |
| Unamortized debt issuance costs                       |       | 10,418                  |       | 10,638                     |       |
| Unrealized gain in fair value of derivative contracts |       | 913                     |       | 2,525                      |       |
| Deferred investment tax credits                       |       | 17,713                  |       | 17,713                     |       |
| Other                                                 |       | 2,026                   |       | 3,359                      |       |
|                                                  |       | 236,575                 |       | 241,981                    |       |
| **Total Assets**                                      |       | $                       | 1,847,611  |                       | $          | 1,839,846 |   |

 

(Continued)

 

*Seeaccompanying Notes to Consolidated Financial Statements.*

 

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**THEEMPIRE DISTRICT ELECTRIC COMPANY**

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

** **
| ** **                                                                                                          | ** ** | **March 31, 2010** | ** ** | **December 31, 2009** | ** ** |
|---------------------------------------------------------------------------------------------------------------------|------------|-------------------------|------------|----------------------------|------------|
| ** **                                                                                                          | ** ** | **($-000’s)**      | ** ** |
| **Capitalization and Liabilities**                                                                                  |       |                    |       |                       |       |
| Common stock, $1 par value, 39,978,511 and 38,112,280 shares  issued and outstanding, respectively                  |       | $                       | 39,979     |                       | $          | 38,112 |   |
| Capital in excess of par value                                                                                      |       | 583,159                 |       | 551,631                    |       |
| Retained earnings                                                                                                   |       | 6,329                   |       | 10,068                     |       |
| Accumulated other comprehensive income/(loss), net of  income tax                                                   |       | (3,375                  | )          | 339                        |       |
| **Total common stockholders’  equity**                                                                         |       | 626,092                 |       | 600,150                    |       |
|                                                                                                                |       |                    |       |                       |       |
| **Long-term debt (net of current  portion):**                                                                       |       |                    |       |                       |       |
| Company obligated mandatorily redeemable trust  preferred securities of subsidiary holding solely parent debentures |       | 50,000                  |       | —                     |       |
| Note payable to securitization trust                                                                                |       | —                  |       | 50,000                     |       |
| Obligations under capital lease                                                                                     |       | 2,526                   |       | 2,563                      |       |
| First mortgage bonds and secured debt                                                                               |       | 339,482                 |       | 339,643                    |       |
| Unsecured debt                                                                                                      |       | 247,852                 |       | 247,950                    |       |
| **Total long-term debt**                                                                                            |       | 639,860                 |       | 640,156                    |       |
| **Total long-term debt and common  stockholders’ equity**                                                      |       | 1,265,952               |       | 1,240,306                  |       |
|                                                                                                                |       |                    |       |                       |       |
| **Current liabilities:**                                                                                            |       |                    |       |                       |       |
| Accounts payable and accrued liabilities                                                                            |       | 45,450                  |       | 67,406                     |       |
| Current maturities of long-term debt                                                                                |       | 50,943                  |       | 51,021                     |       |
| Short-term debt                                                                                                     |       | 29,000                  |       | 50,500                     |       |
| Customer deposits                                                                                                   |       | 10,535                  |       | 10,394                     |       |
| Interest accrued                                                                                                    |       | 12,320                  |       | 5,698                      |       |
| Fair value of derivative contracts                                                                                  |       | 6,860                   |       | 4,337                      |       |
| Taxes accrued                                                                                                       |       | 12,773                  |       | 3,386                      |       |
|                                                                                                                |       | 167,881                 |       | 192,742                    |       |
| **Commitments and contingencies  (Note 7)**                                                                         |       |                    |       |                       |       |
| ** **                                                                                                          |       |                    |       |                       |       |
| **Noncurrent liabilities and  deferred credits:**                                                                   |       |                    |       |                       |       |
| Regulatory liabilities                                                                                              |       | 84,375                  |       | 87,533                     |       |
| Deferred income taxes                                                                                               |       | 204,027                 |       | 194,315                    |       |
| Unamortized investment tax credits                                                                                  |       | 20,040                  |       | 20,125                     |       |
| Pension and other postretirement benefit obligations                                                                |       | 85,439                  |       | 84,240                     |       |
| Unrealized loss in fair value of derivative contracts                                                               |       | 1,463                   |       | 426                        |       |
| Other                                                                                                               |       | 18,434                  |       | 20,159                     |       |
|                                                                                                                |       | 413,778                 |       | 406,798                    |       |
| **Total Capitalization and  Liabilities**                                                                           |       | $                       | 1,847,611  |                       | $          | 1,839,846 |   |

 

*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,**     | ** ** |
| ** **                                                                        | ** ** | **2010**               | ** ** | **2009** | ** ** |
| ** **                                                                        | ** ** | **($-000’s)**     | ** ** |
| **Operating activities:**                                                         | ** ** | ** **             |       |   |   |
| Net  income                                                                       |       | $                      | 8,586      |   | $ | 10,913 |   |
| **Adjustments to reconcile net income to cash  flows from operating activities:** |       |                   |       |   |   |
| Depreciation  and amortization                                                    |       | 14,909                 |       | 14,981 |   |
| Pension  and other postretirement benefit costs                                   |       | 1,652                  |       | 1,484 |   |
| Deferred  income taxes and investment tax credit, net                             |       | 4,249                  |       | 3,883 |   |
| Allowance  for equity funds used during construction                              |       | (1,741                 | )          | (1,407 | ) |
| Stock  compensation expense                                                       |       | 889                    |       | 699 |   |
| Non-cash  loss on derivatives                                                     |       | —                 |       | 5,208 |   |
| Gain  on the sale of assets                                                       |       | —                 |       | (366 | ) |
| **Cash flows impacted by changes in:**                                            |       |                   |       |   |   |
| Accounts  receivable and accrued unbilled revenues                                |       | 8,426                  |       | 9,586 |   |
| Fuel,  materials and supplies                                                     |       | 2,093                  |       | 8,923 |   |
| Prepaid  expenses, other current assets and deferred charges                      |       | (3,170                 | )          | (2,645 | ) |
| Accounts  payable and accrued liabilities                                         |       | (18,451                | )          | (26,906 | ) |
| Interest,  taxes accrued and customer deposits                                    |       | 16,150                 |       | 13,667 |   |
| Other  liabilities and other deferred credits                                     |       | 3,243                  |       | 121 |   |
|                                                                              |       |                   |       |   |   |
| **Net cash provided by operating activities**                                     |       | 36,835                 |       | 38,141 |   |
| ** **                                                                        | ** ** | ** **             | ** ** | ** ** | ** ** |
| **Investing activities:**                                                         | ** ** | ** **             |       |   |   |
| Capital  expenditures — regulated                                            |       | (33,755                | )          | (41,391 | ) |
| Capital  expenditures and other investments — non-regulated                  |       | (1,052                 | )          | (553 | ) |
| Proceeds  from the sale of property, plant and equipment                          |       | —                 |       | 399 |   |
|                                                                              |       |                   |       |   |   |
| **Net cash used in investing activities**                                         |       | (34,807                | )          | (41,545 | ) |
| ** **                                                                        | ** ** | ** **             | ** ** | ** ** | ** ** |
| **Financing activities:**                                                         | ** ** | ** **             | ** ** | ** ** | ** ** |
| Proceeds  from first mortgage bonds - electric                                    |       | —                 |       | 75,000 |   |
| Long-term  debt issuance costs                                                    |       | —                 |       | (2,273 | ) |
| Proceeds  from issuance of common stock, net of issuance costs                    |       | 32,555                 |       | 1,652 |   |
| Net  short-term debt repayments                                                   |       | (21,500                | )          | (54,750 | ) |
| Repayments  of first mortgage bonds                                               |       | (20                    | )          | — |   |
| Dividends                                                                         |       | (12,324                | )          | (10,907 | ) |
| Other                                                                             |       | (382                   | )          | (32 | ) |
| ** **                                                                        |       |                   |       |   |   |
| **Net cash (used in)/provided by financing  activities**                          |       | (1,671                 | )          | 8,690 |   |
| ** **                                                                        |       |                   |       |   |   |
| **Net increase in cash and cash equivalents**                                     |       | 357                    |       | 5,286 |   |
| ** **                                                                        |       |                   |       |   |   |
| **Cash and cash equivalents at beginning of period**                              |       | 5,620                  |       | 2,754 |   |
| ** **                                                                        |       |                   |       |   |   |
| **Cash and cash equivalents at end of period**                                    |       | $                      | 5,977      |   | $ | 8,040 |   |
|                                                                              | ** ** | ** **             |       |   |   |

 

*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 asthree segments:  electric, gas and other.The Empire District Electric Company (EDE), a Kansas corporation organized in1909, is an operating public utility engaged in the generation, purchase,transmission, distribution and sale of electricity in parts of Missouri,Kansas, Oklahoma and Arkansas. As part of our electric segment, we also providewater service to three towns in Missouri. The Empire District Gas Company (EDG)is our wholly-owned subsidiary which provides natural gas distribution tocommunities in northwest, north central and west central Missouri. Our othersegment consists of our fiber optics business.

 

Theaccompanying interim financial statements do not include all disclosuresincluded in the annual financial statements and therefore should be read inconjunction with the financial statements and notes thereto included in ourAnnual Report on Form 10-K for the fiscal year ended December 31,2009.

 

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 31,2009.

 

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

 

*Fair Value.* In September 2009, the FASB amended theaccounting guidance for fair value measurements and disclosures. The amendmentwas issued because some investments, such as some hedge funds and privateequity funds, do not have a readily determinable fair value. This amendmentallows the investor to use net asset value per share (NAV) as a practicalexpedient to fair value so long as the NAV has been calculated in a mannerconsistent with generally accepted accounting principles for investment companies.This amendment is effective for periods ending after December 15, 2009. Asthis guidance provides only disclosure requirements, the adoption of thisstandard did not impact our results of operations, cash flows or financialpositions.

 

InJanuary 2010, the FASB amended the fair value measurements and disclosuresguidance to require additional disclosures about fair value measurements. Therevised guidance requires new disclosures about the transfers in and out ofLevel 1 and 2 measurements, including descriptions of the reasons for thetransfers. Additionally, the reconciliation of Level 3 measurements nowrequires separate presentation of sales, issuances and settlements. Thisguidance for the Level 1 and 2 measurements is effective for periods beginningafter December 15, 2009. The guidance on the Level 3 measurements will beeffective for periods beginning after December 15, 2010. As this guidanceprovides only disclosure requirements, the adoption of this standard did notimpact our results of operations, cash flows or financial positions.

 

*Consolidation.* In June 2009, the FASBamended the accounting guidance for transfers and servicing. This amendment iseffective for annual periods beginning after November 15, 2009. Theamendment removes qualifying special-purpose entities (QSPE) from GAAP.Additionally, the requirements for derecognizing financial assets have beenchanged, and additional disclosures about a transferor’s continuing involvementin transferred financial assets will be required.

 

InJune 2009, the FASB amended the accounting guidance for consolidations.This amendment is effective for annual periods beginning after November 15,2009. The amendment requires an entity to complete a qualitative analysis whendetermining who must consolidate a variable interest entity. Additionally, theamendment requires additional disclosures, and an ongoing reassessment of whomust consolidate a variable interest entity (VIE). The adoption of thisstandard did not have a material impact on our financial statements. Uponadoption of the guidance, we concluded that the consolidation of the EmpireDistrict Electric Trust I was appropriate and it is now reflected in ourconsolidated balance sheets. Our consolidated financial statements include the accountsof our wholly owned subsidiaries and Empire District Electric Trust I. Acontrolling financial

 

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interestis evidenced by either a voting interest greater than 50% or a risk and rewardmodel that identifies us as the primary beneficiary of a VIE. We have evaluatedour long-term purchase power agreements to determine if we hold a variableinterest. This evaluation identified our purchase power agreement for capacityfrom Plum Point Energy Station as a variable interest. For this contract whereit has been determined that we have a variable interest, we consideredoperations and maintenance of the power plant to be the most significantactivity. We do not have control over the operation and maintenance of thepower plant. Additionally, we have not provided debt or equity investments inthe entity, we receive less than the majority of the output of the facilityunder the contract and do not provide any other financial support throughliquidity arrangements, guarantees or other commitments other than the purchasepower agreement described in Note 7. Based on the consideration of thesefactors, we do not consider ourselves to be the primary beneficiary of thisVIE.

 

See Note 1 under “Notes toConsolidated Financial Statements” in our Annual Report on Form 10-K forthe year ended December 31, 2009 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).

 
| **Regulatory Assets and  Liabilities** |   |
|----------------------------------------|--------|

 
| ** **                                                          | ** ** | **March 31, 2010** | ** ** | **December 31, 2009** | ** ** |
|---------------------------------------------------------------------|------------|-------------------------|------------|----------------------------|------------|
| **Regulatory Assets:**                                              |       |                    |       |                       |       |
| Unrecovered  purchase gas costs — gas segment, current         |       | $                       | 250        |                       | $          | 434 |   |
| Unrecovered  electric fuel and purchased power costs — current |       | 3,480                   |       | 338                        |       |
| Regulatory  assets, current**(1)**                                  |       | 3,730                   |       | 772                        |       |
| Pension  and other postretirement benefits**(2)**                   |       | 80,192                  |       | 81,171                     |       |
| Income  taxes                                                       |       | 47,725                  |       | 49,230                     |       |
| Unamortized  loss on reacquired debt                                |       | 11,837                  |       | 12,167                     |       |
| Unamortized  loss on interest rate derivative                       |       | 2,012                   |       | 2,091                      |       |
| Asbury  five-year maintenance                                       |       | 1,287                   |       | 1,401                      |       |
| Ice  storm costs**(3)**                                             |       | 10,733                  |       | 11,673                     |       |
| Deferred  Iatan construction accounting costs**(4)**                |       | 3,932                   |       | 2,732                      |       |
| Asset  retirement obligation                                        |       | 3,308                   |       | 3,264                      |       |
| Unrecovered  electric fuel and purchased power costs                |       | —                  |       | 662                        |       |
| Unsettled  derivative losses — electric segment                |       | 1,216                   |       | 335                        |       |
| Customer  programs                                                  |       | 1,431                   |       | 1,255                      |       |
| System  reliability — vegetation management                    |       | 1,390                   |       | 1,636                      |       |
| Other                                                               |       | 950                     |       | 637                        |       |
| Regulatory  assets, long-term                                       |       | 166,013                 |       | 168,254                    |       |
| **Total**                                                           |       | $                       | 169,743    |                       | $          | 169,026 |   |

 
| ** **                                                     | ** ** | **March 31, 2010** | ** ** | **December 31, 2009** | ** ** |
|----------------------------------------------------------------|------------|-------------------------|------------|----------------------------|------------|
| **Regulatory Liabilities:**                                    |       |                    |       |                       |       |
| Cost  of removal                                               |       | $                       | 55,373     |                       | $          | 53,083 |   |
| Income  taxes                                                  |       | 13,202                  |       | 20,678                     |       |
| Unamortized  gain on interest rate derivative                  |       | 4,009                   |       | 4,051                      |       |
| Pension  and other postretirement benefits**(5)**              |       | 6,211                   |       | 6,415                      |       |
| Over  recovered electric fuel and purchased power costs**(6)** |       | 1,483                   |       | 1,344                      |       |
| Over  recovered purchased gas costs — gas segment         |       | 4,009                   |       | 1,874                      |       |
| Other                                                          |       | 88                      |       | 88                         |       |
| **Total**                                                      |       | $                       | 84,375     |                       | $          | 87,533 |   |

 

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(1) Reflectsunder recovered costs expected to be recovered within the next 12 months inMissouri rates.

(2) Primarilyreflects regulatory assets resulting from the unfunded portion of our pensionand OPEB liabilities and regulatory accounting for EDG acquisition costs.Approximately $0.1 million in pension and other postretirement benefit costshave been recognized since January 1, 2010 to reflect the amortization ofthe regulatory assets that were recorded at the time of the EDG acquisition.

 

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(3) Primarilyreflects ice storm costs incurred in 2007 but also includes deferred wind stormcosts of $0.7 million incurred in May 2009. Consistent with recent ratecase treatment, we expect to recover wind storm costs over a five year periodcommencing when rates go into effect.

(4) Includes$1.1 million of deferred depreciation costs and $2.8 million in carrying costsrelated to construction accounting for Iatan 1 recorded since April 19,2009, in accordance with our regulatory plan. The effect of these deferredcarrying charges is reflected in regulated operating expenses, depreciation andin other interest on the statement of operations. Construction accounting, forpurposes of the regulatory plan, is specific to Iatan 1 and Iatan 2construction and allows us to defer certain charges as regulatory assets,including depreciation and carrying costs, related to operation of thefacilities until the facilities are ultimately included in our rate base. Theamounts deferred, which began at the in-service date for Iatan 1 and will alsobe deferred for Iatan 2 at its in-service date, will then be amortized over thelife of the plants once they are in our rate base.

(5) 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 1,2010, regulatory liabilities and corresponding expenses have been reduced byapproximately $0.1 million as a result of ratemaking treatment.

(6) Primarilyconsists of Missouri over recovered fuel and purchased power costs for thecurrent accumulation period September 2009 through February 2010.

 

Therehave been no changes to the rate base inclusions or amortizable lives of ourregulatory assets and liabilities since December 31, 2009.

 

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

 

Weengage in hedging activities in an effort to minimize our risk from volatilenatural gas prices. We enter into both physical and financial contracts withcounterparties relating to our future natural gas requirements that lock inprices (with respect to a range of predetermined percentages of our expectedfuture natural gas needs) in an attempt to lessen the volatility in our fuelexpense and gain predictability. We recognize that if risk is not timely andadequately balanced or if counterparties fail to perform contractualobligations, actual results could differ materially from intended results.

 

Allderivative instruments are recognized at fair value on the balance sheet withgains and losses deferred in other comprehensive income (in stockholders’equity) for effective instruments related to our electric segment, entered intoprior to September 1, 2008. All other instruments are deferred as aregulatory asset or liability, due to our fuel recovery mechanism, effective September 1,2008 for our electric segment, and for our gas segment.

 

Forthose electric instruments entered into prior to September 1, 2008, werecord unrealized gains/(losses) on the ineffective portion of our gas hedgingactivities in “Fuel and purchased power” under the operating revenue deductionssection of our Statement of Income since all of our gas hedging activities arerelated to stabilizing fuel costs as part of our fuel procurement program andare not speculative activities. Risks and uncertainties affecting thedetermination of fair value include: market conditions in the energy industry, especially the effects ofprice volatility, regulatory and global political environments and requirements,fair value estimations on longer term contracts, the effectiveness of thederivative instrument in hedging the change in fair value of the hedged item,estimating underlying fuel demand and counterparty ability to perform. If weestimate that we have overhedged forecasted demand, the gain or loss on theoverhedged portion will be recognized immediately as fuel and purchased powerexpense in our Consolidated Statement of Income.

 

Asof March 31, 2010 and December 31, 2009, we have recorded thefollowing assets and liabilities representing the fair value of derivativefinancial instruments, (in thousands):

 
| **ASSET DERIVATIVES**                    | ** ** | **March 31,**                       | ** ** | **December 31,** | ** ** |
|------------------------------------------|------------|------------------------------------------|------------|-----------------------|------------|
| **Derivatives  designated as hedging**   | ** ** | ** **                               | ** ** | **2010**              | ** ** | **2009** | ** ** |
| **instruments**                          | ** ** | **Balance Sheet Classification**         | ** ** | **Fair Value**        | ** ** | **Fair Value** | ** ** |
| Natural  gas contracts, electric segment |       | Current  assets                          |       | $                     | 465        |   | $ | 2,233 |   |
|                                     |       | Non-current  assets and deferred charges |       | 879                   |       | 2,438 |   |
|                                          |            |                                          |            |                       |            |  |  |  |  |

 
| **Derivatives not designated as  hedging  instruments due to regulatory accounting** | ** ** | ** **                               | ** ** | ** ** | ** ** | ** ** | ** ** |
|--------------------------------------------------------------------------------------|------------|------------------------------------------|------------|------------|------------|------------|------------|
| Natural  gas contracts, gas segment                                                  |       | Current  assets                          |       | —     |       | 410        |       |
|                                                                                 |       |                                     |       |       |       |       |       |
| Natural  gas contracts, electric segment                                             |       | Current  assets                          |       | —     |       | 139        |       |
|                                                                                 |       | Non-current  assets and deferred charges |       | 34         |       | 87         |       |
| **Total derivatives assets**                                                         | ** ** | ** **                               | ** ** | **$**      | **1,378**  | ** ** | **$**      | **5,307** | ** ** |
|                                                                                      |            |                                          |            |            |            |            |            |  |  |

 

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| **LIABILITY DERIVATIVES**                | ** ** | **March 31,**               | ** ** | **December 31,** | ** ** |
|------------------------------------------|------------|----------------------------------|------------|-----------------------|------------|
| **Derivatives  designated as hedging**   | ** ** | ** **                       | ** ** | **2010**              | ** ** | **2009** | ** ** |
| **instruments**                          | ** ** | **Balance Sheet Classification** | ** ** | **Fair Value**        | ** ** | **Fair Value** | ** ** |
| Natural  gas contracts, electric segment |       | Current  liabilities             |       | $                     | 6,796      |   | $ | 4,123 |   |
|                                          |            |                                  |            |                       |            |  |  |  |  |

 
| **Derivatives not designated as  hedging  instruments due to regulatory accounting** | ** ** | ** **                                    | ** ** | ** ** | ** ** | ** ** | ** ** |
|--------------------------------------------------------------------------------------|------------|-----------------------------------------------|------------|------------|------------|------------|------------|
| Natural  gas contracts, gas segment                                                  |       | Current  liabilities                          |       | $          | —     |       | $          | 214 |   |
|                                                                                 |       |                                          |       |       |       |       |       |
| Natural  gas contracts, electric segment                                             |       | Current  liabilities                          |       | 64         |       | —     |       |
|                                                                                 |       | Non-current  liabilities and deferred credits |       | 1,463      |       | 426        |       |
| **Total derivatives liabilities**                                                    | ** ** | ** **                                    | ** ** | **$**      | **8,323**  | ** ** | **$**      | **4,763** | ** ** |

 

*Electric*

 

A$3.4 million net of tax, unrealized loss representing the fair market value ofour electric segment derivative contracts treated as cash flow hedges andentered into prior to September 1, 2008, is recognized as AccumulatedOther Comprehensive Income in the capitalization section of the balance sheetas of March 31, 2010. The tax effect of $2.0 million on this loss isincluded in deferred taxes. These amounts will be adjusted cumulatively on amonthly basis during the determination periods, beginning April 1, 2010and 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 is reclassified to fuel expense and issubject to the fuel adjustment clause. As of March 31, 2010, approximately$6.3 million of unrealized losses are applicable to financial instruments whichwill settle within the next twelve months. The unrealized losses or gains fromnew cash flow hedges entered into after September 1, 2008, are recorded inregulatory assets or liabilities. This is in accordance with ASC guidance onaccounting for regulated operations, given that those regulatory assets andliabilities are probable of recovery through our fuel adjustment mechanism.Unrealized gains and losses from cash flow hedges existing at September 1,2008 continue to be recorded through comprehensive income.

 

Thefollowing tables set forth the actual pre-tax gains/(losses) and the mark tomarket effect of unsettled positions from the qualified portion of our hedgingactivities for settled contracts for the electric segment for each of theperiods ended March 31, (in thousands):

 
| ** **                              | ** ** | **Income Statement  Classification of** | ** ** | **Amount of Gain / (Loss) Reclassed from OCI into  Income (Effective portion)** | ** ** |
|-----------------------------------------|------------|-----------------------------------------|------------|---------------------------------------------------------------------------------|------------|
| **Derivatives  in Cash Flow Hedging**   | ** ** | **Gain / (Loss) on**                    | ** ** | **Three Months Ended**                                                          | ** ** | **Twelve Months Ended** | ** ** |
| **Relationships  - Electric Segment**   | ** ** | **Derivative**                          | ** ** | **2010**                                                                        | ** ** | **2009** | ** ** | **2010** | ** ** | **2009** | ** ** |
| Commodity contracts                     |       | Fuel  and purchasedpower expense        |       | $                                                                               | —     |   | $ | (4,926 | ) | $ | (8,643 | ) | $ | (1,913 | ) |
|                                    |       |                                    |       |                                                                            |       |   |   |   |   |   |   |
| **Total Effective - Electric  Segment** | ** ** | ** **                              | ** ** | **$**                                                                           | **—** | ** ** | **$** | **(4,926** | **)** | **$** | **(8,643** | **)** | **$** | **(1,913** | **)** |

 
| ** **                              | ** ** | **Statement of**                   | ** ** | **Amount of Gain / (Loss) Recognized in OCI on  Derivative (Effective portion)** | ** ** |
|-----------------------------------------|------------|------------------------------------|------------|----------------------------------------------------------------------------------|------------|
| **Derivatives  in Cash Flow Hedging**   | ** ** | **Comprehensive**                  | ** ** | **Three Months Ended**                                                           | ** ** | **Twelve Months Ended** | ** ** |
| **Relationships  - Electric Segment**   | ** ** | **Income**                         | ** ** | **2010**                                                                         | ** ** | **2009** | ** ** | **2010** | ** ** | **2009** | ** ** |
| Commodity contracts                     |       | Fuel  and purchased  power expense |       | $                                                                                | (6,001     | ) | $ | (9,333 | ) | $ | (6,244 | ) | $ | (37,749 | ) |
|                                    |       |                               |       |                                                                             |       |   |   |   |   |   |   |
| **Total Effective - Electric  Segment** | ** ** | ** **                         | ** ** | **$**                                                                            | **(6,001** | **)** | **$** | **(9,333** | **)** | **$** | **(6,244** | **)** | **$** | **(37,749** | **)** |

 

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

 

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| ** **                                | ** ** | **Statement of Income  Classification of** | ** ** | **Amount of Gain / (Loss) Recognized in Income on  Derivative (Ineffective Portion)** | ** ** |
|-------------------------------------------|------------|--------------------------------------------|------------|---------------------------------------------------------------------------------------|------------|
| **Derivatives  in Cash Flow Hedging**     | ** ** | **Gain/ (Loss) on**                        | ** ** | **Three Months Ended**                                                                | ** ** | **Twelve Months Ended** | ** ** |
| **Relationships  - Electric Segment**     | ** ** | **Derivative**                             | ** ** | **2010**                                                                              | ** ** | **2009** | ** ** | **2010** | ** ** | **2009** | ** ** |
| Commodity contracts                       |       | Fuel  and purchased                        |       |                                                                                  |       |   |   |   |   |   |   |
|                                      |       | power  expense                             |       | $                                                                                     | —     |   | $ | — |   | $ | — |   | $ | (2 | ) |
| **Total Ineffective - Electric  Segment** | ** ** | ** **                                 | ** ** | **$**                                                                                 | **—** | ** ** | **$** | **—** | ** ** | **$** | **—** | ** ** | **$** | **(2** | **)** |

 

Inaccordance with the Missouri fuel adjustment clause discussed above, therecoverable portion of any gain or loss is recorded in a regulatory asset orliability account. The following tables set forth “mark-to-market” pre-tax gains/(losses)from derivatives not designated as hedging instruments for the electric segmentfor each of the periods ended March 31, (in thousands):

 
| **Derivatives  Not Designated as  Hedging Instruments — Due to** | ** ** | **Balance Sheet **          | ** ** | **Amount of Gain / (Loss) Recognized on  Balance Sheet** | ** ** |
|-----------------------------------------------------------------------|------------|----------------------------------|------------|----------------------------------------------------------|------------|
| **Regulatory  Accounting**                                            | ** ** | **Classification of Gain /**     | ** ** | **Three Months Ended**                                   | ** ** | **Twelve Months Ended** | ** ** |
| **Electric  Segment**                                                 | ** ** | **(Loss) on Derivative**         | ** ** | **2010**                                                 | ** ** | **2009** | ** ** | **2010** | ** ** | **2009** | ** ** |
|                                                                  |       |                             |       |                                                     |       |   |   |   |   |   |   |
| Commodity contracts — electric segment                           |       | Regulatory  (assets)/liabilities |       | $                                                        | (1,292     | ) | $ | 180 |   | $ | (1,567 | ) | $ | (1,036 | ) |
| **Total Electric Segment**                                            | ** ** | ** **                       | ** ** | **$**                                                    | **(1,292** | **)** | **$** | **180** | ** ** | **$** | **(1,567** | **)** | **$** | **(1,036** | **)** |

 
| **Derivatives  Not Designated as  Hedging Instruments — Due to** | ** ** | **Statement of  Operations  Classification of** | ** ** | **Amount of Gain / (Loss) Recognized in Income on  Derivative** | ** ** |
|-----------------------------------------------------------------------|------------|-------------------------------------------------|------------|-----------------------------------------------------------------|------------|
| **Regulatory  Accounting**                                            | ** ** | **Gain / (Loss) on**                            | ** ** | **Three Months Ended**                                          | ** ** | **Twelve Months Ended** | ** ** |
| **Electric  Segment(1)**                                              | ** ** | **Derivative**                                  | ** ** | **2010**                                                        | ** ** | **2009** | ** ** | **2010** | ** ** | **2009** | ** ** |
|                                                                  |       |                                            |       |                                                            |       |   |   |   |   |   |   |
| Commodity contracts                                                   |       | Fuel  and purchased                             |       |                                                            |       |   |   |   |   |   |   |
|                                                                  |       | power  expense                                  |       | $                                                               | (262       | ) | $ | 50 |   | $ | (1,415 | ) | $ | (279 | ) |
| **Total Electric Segment**                                            | ** ** | ** **                                      | ** ** | **$**                                                           | **(262**   | **)** | **$** | **50** | ** ** | **$** | **(1,415** | **)** | **$** | **(279** | **)** |

 

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**(1) **All of our gas hedging activities are related to stabilizing fuel costsas part of our fuel procurement program and are not speculative activities. Ifconditions change, such as a planned unit outage, we may need to de-designateand/or unwind some of our previous derivatives. In this instance, thesederivatives would be classified into the category above.

 

Wealso enter into fixed-price forward physical contracts for the purchase ofnatural gas, coal and purchased power. These contracts are not subject to fairvalue accounting because they are considered to be normal purchases and are notderivatives. We have a process in place to determine if any future executedcontracts that otherwise qualify for the normal purchase exception contain aprice adjustment feature and will account for these contracts accordingly.

 

Asof April 23, 2010, 71% of our anticipated volume of natural gas usage forour electric operations for the remainder of 2010 is hedged, either throughphysical (2.2 million Dth) or financial contracts (3.0 million Dth), at anaverage price of $6.391 per Dekatherm (Dth). In addition, the following volumesand percentages of our anticipated volume of natural gas usage for our electricoperations for the next three years are hedged at the following average pricesper Dth:

 
| **Year** | ** ** | **% Hedged** | ** ** | **Dth Hedged** | ** ** | **Average Price** | ** ** |
|----------|------------|--------------|------------|----------------|------------|-------------------|------------|
| 2011(1)  |       | 75           | %          | 5,410,000      |       | $                 | 5.809      |   |
| 2012(1)  |       | 40           | %          | 3,085,000      |       | $                 | 7.016      |   |
| 2013     |       | 25           | %          | 1,800,000      |       | $                 | 6.862      |   |
| 2014     |       | 8            | %          | 620,000        |       | $                 | 6.115      |   |

 

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(1)          2.0 million Dth and 1.4million Dth of the anticipated volume of natural gas usage for 2011 and 2012,respectively, are hedged through financial derivative contracts.

 

Weutilize the following procurement guidelines for our electric segment:  currentyear up to 100% of expected gas usage, first year minimum of 60%, second yearminimum of 40%, third year

 

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minimum of 20% and fourth year minimum of 10%,subject to a maximum of 80% of the expected gas usage in any one year.

 

*Gas*

 

We attempt to mitigate our natural gas price riskfor our gas segment by a combination of (1) injecting natural gas intostorage during the off-heating season months, (2) purchasing physicalforward contracts and (3) purchasing financial derivative contracts. Wetarget to have 95% of our storage capacity full by November 1 for theupcoming winter heating season. As the winter progresses, gas is withdrawn fromstorage to serve our customers. As of March 31, 2010, we had 0.3 millionDths in storage on the three pipelines that serve our customers. Thisrepresents 17% of our storage capacity. We have an additional 0.2million Dths hedged through financial derivative and physical contracts. Our long-term hedge strategy is to mitigateprice volatility for our customers by hedging a minimum of 50% of current year,up to 50% of second year and up to 20% of third year expected gas usage by thebeginning of the Actual Cost Adjustment (ACA) year at September 1. A Purchased Gas Adjustment (PGA) clause isincluded in our rates for our gas segment operations, therefore, we mark tomarket any unrealized gains or losses and any realized gains or losses relatingto financial derivative contracts to a regulatory asset or regulatory liabilityaccount on our balance sheet.

 

Thefollowing table sets forth “mark-to-market” pre-tax gains / (losses) fromderivatives not designated as hedging instruments for the gas segment for eachof the periods ended March 31, (in thousands).

 
| **Derivatives  Not Designated as  Hedging Instruments Due to** | ** ** | **Balance Sheet  Classification of ** | ** ** | **Amount of Gain / (Loss) Recognized on  Balance Sheet** | ** ** |
|----------------------------------------------------------------|------------|--------------------------------------------|------------|----------------------------------------------------------|------------|
| **Regulatory  Accounting — Gas**                          | ** ** | **Gain or (Loss) on**                      | ** ** | **Three Months Ended**                                   | ** ** | **Twelve Months Ended** | ** ** |
| **Segment**                                                    | ** ** | **Derivative**                             | ** ** | **2010**                                                 | ** ** | **2009** | ** ** | **2010** | ** ** | **2009** | ** ** |
| ** **                                                     | ** ** | ** **                                 |       |                                                     |       |   |   |   |   |   |   |
| Commodity contracts                                            |       | Regulatory  (assets)/  liabilities         |       | $                                                        | (127       | ) | $ | (1,839 | ) | $ | 1,040 |   | $ | (11,102 | ) |
| **Total - Gas Segment**                                        | ** ** | ** **                                 | ** ** | **$**                                                    | **(127**   | **)** | **$** | **(1,839** | **)** | **$** | **1,040** | ** ** | **$** | **(11,102** | **)** |

 

*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, 2010 is$3.2 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, 2010, we would have been requiredto post $1.2 million of collateral with one of our counterparties. On March 31,2010, we had no collateral posted with this counterparty.

 

**Note 5—Fair Value Measurements**

 

Theaccounting guidance on fair value measurements establishes a three-tier fairvalue hierarchy, which prioritizes the inputs used in measuring fair value.These tiers include: (i) Level 1, defined as quoted prices in activemarkets for identical instruments; (ii) Level 2, defined as inputs otherthan quoted prices in active markets that are either directly or indirectlyobservable; and (iii) Level 3, defined as unobservable inputs in whichlittle or no market data exists, therefore requiring an entity to develop itsown assumptions. Our Level 2 fair value measurements consist of both quotedprice inputs and inputs provided by a third party that are derived principallyfrom or corroborated by observable market data by correlation. Our Level 3 fairvalue measurements consist of both quoted price inputs and unobservable quotedinputs provided by a third party.

 

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Theguidance also requires that the fair value measurements of assets andliabilities reflect the nonperformance risk of counterparties and the reportingentity, as applicable. Therefore, using credit default spreads, we factored theimpact of our own credit standing and the credit standing of ourcounterparties, as well as any potential credit enhancements (e.g. collateral)into the consideration of nonperformance risk for both derivative assets andliabilities. The results of this analysis were not material to the financialstatements.

 

Thefollowing fair value hierarchy table presents information about our assetsmeasured at fair value using the market value approach on a recurring basis asof March 31, 2010 and December 31, 2009.

 
| ** **                                 | ** ** | **Fair Value Measurements at Reporting Date Using** | ** ** |
|--------------------------------------------|------------|-----------------------------------------------------|------------|
| **($ in  000’s)  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)** | ** ** |
| ** **                                 | ** ** | ** **                                          | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| ** **                                 | ** ** | ** **                                          | ** ** | **March 31,  2010** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Commodity  contracts assets/(liabilities)* |       | $                                                   | (6,945     | ) | $ | (6,945 | ) | $ | — |   | $ | — |   |
|                                       |       |                                                |       |   |   |   |   |   |   |
|                                       |       |                                                | ** ** | ** ** |   |   |   |   |   |
|                                       |       |                                                | ** ** | **December 31,  2009** |   |   |   |   |   |
| Commodity  contracts assets/(liabilities)* |       | $                                                   | 544        |   | $ | 544 |   | $ | — |   | $ | — |   |

 

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*Theonly recurring measurements are commodity contract derivatives. Therefore,assets and liabilities are netted together in the table above.

 

Thefollowing tables present the net fair value on a recurring basis usingsignificant unobservable inputs (Level 3) during the periods ended March 31,2010 and 2009:

 

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

 
| ** **                                                                   | ** ** | **2010**                  | ** ** | **2009**                  | ** ** |
|------------------------------------------------------------------------------|------------|---------------------------|------------|---------------------------|------------|
| ** **                                                                   | ** ** | **Derivatives Commodity** | ** ** | **Derivatives Commodity** | ** ** |
| **($ in  000’s)**                                                  | ** ** | **Contracts(1)**          | ** ** | **Contracts(1)**          | ** ** |
| Beginning  Balance, January 1,                                          |       | $                         | —     |                      | $          | 6,208 |   |
| Total  gains or (losses) (realized/unrealized)                               |       |                      |       |                      |       |
| Included  in earnings (or changes in net assets)                             |       | —                    |       | —                    |       |
| Included  in comprehensive income                                            |       |                      |       | (2,456                    | )          |
| Purchases,  issuances, and settlements                                       |       | —                    |       | —                    |       |
| Transfers  into and (out of) Level 3                                         |       | —                    |       | —                    |       |
| Ending  Balance, March 31,                                              |       | $                         | —     |                      | $          | 3,752 |   |
| Changes  in unrealized gains relating to assets still held at reporting date |       | $                         | —     |                      | $          | (2,456 | ) |

 

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(1) Netcommodity contracts at March 31, 2010 and 2009 included zero and $3.8million, respectively, in derivative assets, and no derivative liabilities.

 

**FairValue Measurements Using Significant Unobservable Inputs (Level 3) — 12 MonthsEnded**

 
| ** **                                                                   | ** ** | **2010**                  | ** ** | **2009**                  | ** ** |
|------------------------------------------------------------------------------|------------|---------------------------|------------|---------------------------|------------|
| ** **                                                                   | ** ** | **Derivatives Commodity** | ** ** | **Derivatives Commodity** | ** ** |
| **($ in  000’s)**                                                  | ** ** | **Contracts(1)**          | ** ** | **Contracts(1)**          | ** ** |
| Beginning  Balance, April 1,                                            |       | $                         | 3,752      |                      | $          | 12,266 |   |
| Total  gains or (losses) (realized/unrealized)                               |       |                      |       |                      |       |
| Included  in earnings (or changes in net assets)                             |       |                      |       | —                    |       |
| Included  in comprehensive income                                            |       | 718                       |       | (8,514                    | )          |
| Purchases,  issuances, and settlements                                       |       |                      |       | —                    |       |
| Transfers  into and (out of) Level 3(2) (3)                             |       | (4,470                    | )          | —                    |       |
| Ending  Balance, March 31,                                              |       | $                         | —     |                      | $          | 3,752 |   |
|                                                                         |       |                      |       |                      |       |
| Changes  in unrealized gains relating to assets still held at reporting date |       | $                         | —     |                      | $          | (8,514 | ) |

 

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(1) Netcommodity contracts at March 31, 2010 and 2009 included zero and $3.8million, respectively, in derivative assets, and no derivative liabilities.

 

(2) Transferredfrom Level 3 to Level 1 due to an increase in availability of observable marketdata and increased market liquidity for these derivatives.

 

(3) Thecompany’s policy is to recognize transfers in and out of a level as of the endof the period.

 

*Long-Term Debt*

 

Thecarrying amount of our total debt exclusive of capital leases at March 31,2010, was $687.9 million compared to a fair market value of approximately$696.8 million. These estimates were based on the quoted market prices for thesame or similar issues or on the current rates offered to us for debt of thesame remaining maturities. The estimated fair market value may not representthe actual value that could have been realized as of March 31, 2010 orthat will be realizable in the future.

 

**Note 6— Financing**

 

OnFebruary 25, 2009, we entered into an equity distribution agreement withUBS Securities LLC (UBS). Under the terms of the agreement, as amended, we mayoffer and sell shares of our common stock, par value $1.00 per share, having anaggregate offering amount of up to $120 million from time to time through UBS,as sales agent. We have used and intend to continue to use the net proceedsfrom this equity distribution program to repay short-term debt and for generalcorporate purposes, including the funding of our current construction program.During the first quarter of 2010, we issued and sold 1,678,341 shares of ourcommon stock pursuant to this equity distribution program, at an average priceper share of $18.27, resulting in proceeds to us of approximately $29.7 million(after payment of approximately $0.9 million in commissions to the salesagent). Since inception of the program, in the aggregate, we have issued andsold 5,479,863 shares pursuant to the program, resulting in net proceeds to usof approximately $96.9 million. Sales of the shares pursuant to the equitydistribution agreement will be made at market prices or as otherwise agreedwith UBS. Under the terms of the program agreement, we may also sell shares toUBS as principal for UBS’ own account at a price agreed upon at the time ofsale.

 

OnJuly 15, 2005, we entered into a $150 million unsecured revolving creditfacility which was scheduled to terminate on July 15, 2010. On March 14,2006, we entered into the First Amended and Restated Unsecured Credit Agreementwhich amended and restated the $150 million unsecured revolving creditfacility. The principal amount of the credit facility was increased to $226million, with the additional $76 million allocated to support a letter ofcredit issued in connection with our participation in the Plum Point EnergyStation project. This extra $76 million of availability reduces over a fouryear period in line with the amount of construction expenditures we owe forPlum Point Unit 1 and was $7.5 million as of May 1, 2010. On January 26,2010, we entered into the Second Amended and Restated Unsecured CreditAgreement which amended and restated this facility again. This agreement extendsthe termination date of the revolving credit facility from July 15, 2010to January 26, 2013. In addition, the pricing and fees under the facilitywere amended. Interest on borrowings under the facility accrues at a rate equalto, at our option, (i) the highest of (A) the bank’s prime commercialrate, (B) the federal funds effective rate plus 0.5% or (C) one monthLIBOR plus 1.0%, plus a margin or (ii) one month, two month or three monthLIBOR, in each case, plus a margin. Each margin is based on our current creditratings and the pricing schedule in the facility. As of the date hereof, andbased on our current credit ratings, the LIBOR margin under the facilityincreased from 0.80% to 2.70%. A facility fee is payable quarterly on the fullamount of the commitments under the facility and a usage fee is payable on thefull amount of the commitments under the facility for any period in which wehave drawn less than 33% of the total revolving commitments under the facility,in each case based on our current credit ratings. In addition, upon enteringinto the amended and restated facility, we paid an upfront fee to the revolvingcredit banks of $900,000 in the aggregate. The aggregate amount of the revolvingcommitments remained unchanged at $150 million and there were no other materialchanges to the terms of the facility. The facility is used for working capital,general corporate purposes and to back-up our use of commercial paper. Thisfacility requires our total indebtedness (which does not include our trustpreferred securities) to be less than 62.5% of our

 

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total capitalization at the end of eachfiscal quarter and our EBITDA (defined as net income plus interest, taxes,depreciation and amortization) to be at least two times our interest charges(which includes interest on the trust preferred securities) for the trailingfour fiscal quarters at the end of each fiscal quarter. Failure to maintainthese ratios will result in an event of default under the credit facility andwill prohibit us from borrowing funds thereunder. As of March 31, 2010, weare in compliance with these ratios. This credit facility is also subject tocross-default if we default 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 was $14.0 million ofoutstanding borrowings under this agreement at March 31, 2010 and anadditional $15.0 million was used to back up our outstanding commercial paper.

 

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 identical covenants and terms as (other than pricing) ourSecond Amended and Restated Unsecured Credit Agreement dated January 26,2010 discussed above. There were no borrowings under this agreement at March 31,2010.

 

**Note 7— Commitments and Contingencies**

 

Weare a party to various claims and legal proceedings arising out of the normalcourse of our business. Management regularly analyzes this information, and hasprovided accruals for any liabilities, in accordance with the guidelinespresented in the ASC on accounting for contingencies. In the opinion ofmanagement, it is not probable, given the company’s defenses, that the ultimateoutcome of these claims and lawsuits will have a material adverse effect uponour financial condition, or results of operations or cash flows.

 

OnMay 22, 2009, a suit was filed in the Circuit Court of Platte CountyMissouri by several individuals and Class Representatives alleging damagesto land, structures, equipment and devastation of crops due to inappropriatemanagement of the levee system around the Iatan Generating Station, of which weare 12% owners. No procedural schedule has been established and we are unableto predict the outcome of the law suit.

 

**Coal, Natural Gas and Transportation Contracts**

 

Wehave entered into long and short-term agreements to purchase coal and naturalgas for our energy supply and natural gas operations. Under these contracts,the natural gas supplies are divided into firm physical commitments andderivatives that are used to hedge future purchases. In the event that this gascannot be used at our plants, the gas would be liquidated at market price. Thefirm physical gas and transportation commitments are as follows (in millions):

 
| **Firm  physical gas and transportation contracts**  |   |   |   |
|------------------------------------------------------|--------|--------|--------|
|                                                 |   |   |   |
| April 1, 2010 through December 31, 2010    |   | $      | 28.2   |   |
| January 1, 2011 through December 31,  2012 |   | 61.7   |   |
| January 1, 2013 through December 31,  2014 |   | 36.9   |   |
| January 1, 2015 and beyond                      |   | 39.2   |   |
|                                                      |        |        |        |  |

 

Wehave coal supply agreements and transportation contracts in place to providefor the delivery of coal to the plants. These contracts are written with ForceMajeure clauses that enable us to reduce tonnages or cease shipments undercertain circumstances or events. These include mechanical or electricalmaintenance items, acts of God, war or insurrection, strikes, weather and otherdisrupting events. This reduces the risk we have for not taking the minimumrequirements of fuel under the contracts. We have accepted a binding proposalin the first quarter of 2010 to transport coal beginning June 30, 2010,which replaces an existing contract that expires June 29, 2010. Theproposal term is for six and one-half years and the minimum payments totalapproximately $91.0

 

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million, subject to final contract terms. Theminimum requirements for our coal and coal transportation contracts are asfollows (in millions):

 
| **Coal  and coal transportation contracts**          |   |   |   |
|------------------------------------------------------|--------|--------|--------|
|                                                 |   |   |   |
| April 1, 2010 through December 31, 2010    |   | $      | 23.0   |   |
| January 1, 2011 through December 31,  2012 |   | 44.6   |   |
| January 1, 2013 through December 31,  2014 |   | 33.4   |   |
| January 1, 2015 and beyond                      |   | 28.0   |   |
|                                                      |        |        |        |  |

 

**Purchased Power**

 

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

 

Wehave contracted with Westar Energy for the purchase of capacity and energythrough May 31, 2010. Commitments under this contract total approximately$2.7 million through May 31, 2010.

 

Wealso have a long-term (30 year) agreement for the purchase of capacity from thePlum Point Energy Station, a new 665-megawatt, coal-fired generating facilitywhich is being built by Dynegy near Osceola, Arkansas. Construction began inthe spring of 2006 and Dynegy reports that substantial completion is scheduledfor summer 2010. We have the option to purchase an undivided ownership interestin the 50 megawatts covered by the purchased power agreement in 2015.Commitments under this contract total approximately $48.0 million through June 30,2015. Due to the expected in-service delays of Plum Point and Iatan 2, we havearranged for sufficient alternative transmission and generating capacity tomeet our expected needs for May 2010 through July 2010. Theincremental costs associated with this alternative will not have a materialimpact on our earnings.

 

Wehave a 20-year purchased power agreement with Cloud County Windfarm, LLC, ownedby Horizon Wind Energy, Houston, Texas to purchase the energy generated at theapproximately 105-megawatt Phase 1 Meridian Way Wind Farm located in CloudCounty, Kansas commencing 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 underGenerally Accepted Accounting Principles (GAAP), payments for these windagreements are recorded as purchased power expenses, and, because of the contingentnature of these payments, are not included in our operating lease obligations.

 

**New Construction**

 

OnMarch 14, 2006, we entered into contracts to purchase a 50 megawattundivided interest in the Plum Point Energy Station described above. Dynegy reportsthat the unit is scheduled to be substantially complete (or in service) in thesummer of 2010. The estimated cost is approximately $88.0 million, excludingallowance for funds used during construction (AFUDC). Our share of the PlumPoint costs through March 31, 2010 was $85.7 million.

 

On June 13, 2006, we announced we had entered into an agreementwith Kansas City Power & Light (KCP&L) to purchase an undividedownership interest in the coal-fired Iatan 2 generating facility. We will own12%, or approximately 100 megawatts, of the 850-megawatt unit. On January 13,2010, KCP&L announced that, due to construction delays and unusually coldweather, it was shifting the anticipated in-service date for Iatan 2 from latesummer 2010 to the fall of 2010 and commencing a cost and schedule reforecastprocess as the project enters the startup phase. On April 8, 2010,KCP&L announced the results of the reforecast process. KCP&L currentlyprojects a fourth quarter 2010 in-service date for Iatan 2. Our share of theIatan 2 construction costs, excluding AFUDC and Empire specific costs, isexpected to be in a range of approximately $229 million to $239 million, ascompared to the previous estimated range of $218 million to $230 million. Ourshare of the Iatan 2 costs through March 31, 2010 was $208.7 million.

 

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Wefiled our initial rate increase request with the Missouri Public ServiceCommission (MPSC) on October 29, 2009, for an annual increase in baserates for our Missouri electric customers in the amount of $68.2 million, or19.6%. This request was primarily designed to allow us to recover the costsassociated with environmental upgrades at Iatan 1 and our investment in newgenerating units at Iatan 2 and the Plum Point Generating Station. As a resultof the delay in the Iatan 2 project, however, we have agreed to not seek apermanent increase in the current rate case for any costs associated with theIatan 2 unit with the exception of that portion of the Iatan 2 common plantneeded to operate Iatan 1. We anticipate filing a rate case at the conclusionof this case to recover the Iatan 2 costs. We have also agreed to the use ofconstruction accounting for our Plum Point project such as we use for our Iatan2 project. Construction accounting allows us to defer certain charges asregulatory assets, including depreciation, operating expenses and carryingcosts, related to operation of the facilities until the facilities areultimately included in our rate base.

 

We also filed a request with the Kansas Corporation Commission (KCC) onNovember 4, 2009 for an annual increase in base rates for our Kansaselectric customers in the amount of $5.2 million, or 24.6%. This request isprimarily to allow us to recover capital expenditures associated with ourinvestment in new generating units at Iatan 2 and the Plum Point GeneratingStation, environmental upgrades at Iatan 1 completed in 2009 and at our Asburyplant completed in 2008, and our Riverton 12 unit that went on line in 2007.

 

On March 25, 2010, we requested a capital cost recovery rider(CCRR) at the Oklahoma Corporation Commission (OCC). The rider is designed torecover the carrying costs on our capital investment for generation,transmission and distribution assets that have been added to the system sinceour last Oklahoma general rate case (May 2003), as well as investmentsmade on an ongoing basis. As requested, the operation of the CCRR wouldincrease our operating revenue in Oklahoma in a series of three steps to befollowed with a general rate case in 2011. If the CCRR is authorized by theOCC, it is expected to result in a maximum overall increase in Oklahomarevenues of approximately $3 million pre-tax, or approximately 33%.

 

Thereare risks that actual costs may exceed budget estimates, delays may occur in obtainingpermits and materials, suppliers and contractors may not perform as requiredunder their contracts, there may be inadequate availability, productivity or increasedcost of qualified craft labor, start-up activities may take longer thancurrently planned, the scope and timing of projects may change, there-baselined schedule may not be met and other events beyond our control,including the failure of one or more of the generation plant co-owners to paytheir share of construction, operations and maintenance costs, may occur thatmay materially affect the schedule, budget, cost and performance of theseprojects.

 

**Leases**

 

Wehave purchased power agreements with Cloud County Windfarm, LLC and Elk RiverWindfarm, LLC, which are considered operating leases for GAAP purposes. Detailsof these arrangements are disclosed in the Purchased Power section of thisnote.

 

We also currently have short-term operating leasesfor two unit trains to meet coal delivery demands, for garage and officefacilities for our electric segment and for six service center properties forour gas segment. In addition, we have capital leases for certain officeequipment and a unit train for our Plum Point generating facility.

 

**Environmental Matters**

 

Weare subject to various federal, state, and local laws and regulations withrespect to air and water quality and with respect to hazardous and toxic materialsand hazardous and other wastes, including their identification, transportation,disposal, record-keeping and reporting, as well as remediation of contaminatedsites and other environmental matters. We believe that our operations are inmaterial compliance with present environmental laws and regulations.Environmental requirements have changed frequently and become more stringentover time. We expect this trend to continue. While we are not in a position to accurately estimate compliance costsfor any new requirements, we expect them to be material, although recoverablein rates.

 

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***Electric Segment***

 

*Air.*

 

TheFederal Clean Air Act (CAA) and comparable state laws regulate air emissionsfrom stationary sources such as electric power plants through permitting and/oremission control and related requirements. These requirements include maximumemission limits on our facilities for sulfur dioxide (SO2), particulate matter, andnitrogen oxides (NOx). In the future they are also likely to include limits onemissions of mercury, and so-called greenhouse gases (GHG) such as carbondioxide (CO2) and methane.

 

*Permits*

 

Underthe CAA we have obtained site operating permits, which are valid for fiveyears, for each of our plants. We expect to receive renewed permits for theAsbury, State Line and Energy Center plants in 2010.

 

TheCAA also requires a permit, and if necessary installation of pollution controlequipment, when making a major modification or a change in operation if suchmodification or change is likely to cause a significant net increase inregulated emissions. In May 2008, KCPL received a Federal grand jurysubpoena under the CAA requesting documents relating to capital projects atIatan 1. We own 12% of Iatan 1. We were informed by KCPL in September 2009that the US Department of Justice does not intend to bring charges under theCAA in connection with repair work, maintenance or modifications at Iatan Unit1.

 

*SO**2** Emissions*

 

TheCAA regulates the amount of SO2 an affectedunit can emit through, among other things, a cap and trade program. Eachexisting affected unit has been allocated a specific number of emissionallowances by the U.S. Environmental Protection Agency (EPA), each of whichallows the holder to emit one ton of SO2. Covered utilities, such as Empire, must have emissionallowances equal to the number of tons of SO2 emittedduring a given year by each of their affected units. Allowances in excess ofthe annual emissions are banked for future use.

 

In2009, our SO2 emissions exceeded the annual allocations.This deficit was covered by our banked allowances. When our SO2 allowance bank is exhausted, currentlyestimated to be mid-2011, we will need to purchase additional SO2 allowances or build a Flue GasDesulphurization (FGD) scrubber system at our Asbury Plant. Based on currentand projected SO2 allowance prices and high-level estimated FGDscrubber construction costs ($81 million in 2010 dollars), it will likely bemore economical for us to purchase SO2 allowancesthan to build a scrubber at the Asbury Plant. If we were to purchase SO2 allowances, we would expect their cost to befully recoverable in our rates.

 

*NOxEmissions*

 

TheCAA regulates the amount of NOx an affected unit can emit. Each of our affectedunits is in compliance with the NOx limits applicable to it as currentlyoperated.

 

OnJanuary 6, 2010, the EPA proposed to lower the primary National AmbientAir Quality Standard (NAAQS) for ozone designed to protect public health and toset a secondary NAAQS for ozone designed to protect sensitive vegetation and ecosystems.The EPA intends to issue final standards by August 31, 2010. Once finalstandards are set, states will be required to develop State ImplementationPlans (SIPs) which reflect these standards. Ozone, also called ground levelsmog, is formed by the mixing of NOx and Volatile Organic Compounds in thepresence of sunlight.

 

*CleanAir Interstate Rule (CAIR)*

 

In2005, the EPA promulgated CAIR under the CAA. CAIR generally calls forfossil-fueled power plants greater than 25 megawatts to reduce emission levelsof SO2 and NOx in 28 states, including Missouri,where our Asbury, Energy Center, State Line and Iatan Units No. 1 and No. 2are

 

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locatedand Arkansas where the Plum Point Energy Station is located. Kansas is notincluded in CAIR and our Riverton Plant is not affected.

 

In2008, the U.S. Court of Appeals for the District of Columbia vacated CAIR andremanded it back to EPA for further consideration, but also stayed its vacatur.As a result, CAIR became effective for NOx on January 1, 2009 and for SO2 on January 1, 2010.

 

The CAIR requires covered states(including Missouri and Arkansas) to develop SIPs to comply with specific NOxand SO2 state-wide annual budgets. Missouri andArkansas have approved SIPs and, based on these SIPs, we believe we will haveexcess NOx allowances for 2010 which will be banked for future use. However, SO2 allowances must be utilized at a 2:1 ratio forour Missouri units as compared to our non-CAIR Kansas units beginning in 2010.As a result, based on current SO2allowance usageprojections, we expect to exhaust our banked allowances by mid-2011 and, asdiscussed above, will need to purchase additional SO2 allowances or build a scrubber at our AsburyPlant.

 

In order to meet CAIR requirements, aSelective Catalytic Reduction system (SCR), FGD scrubber system and baghousewere installed at our Iatan 1 plant and an SCR was installed at our Asburyplant in 2009.

 

TheEPA has announced that proposed revisions to CAIR will be published in May 2010with the final regulations expected 12-14 months after the proposal. It is notpossible at this time to accurately predict what the new requirements will beor their impact on our operations.

 

*Mercuryand Electric Steam Generating Unit (EGU) Maximum Achievable Control Technology(MACT)*

 

In2005, the EPA issued the Clean Air Mercury Rule (CAMR) under the CAA. Itset limits on mercury emissions by power plants and created a market-based capand trade system expected to reduce nationwide mercury emissions in two phases.New mercury emission limits for Phase 1 were to go into effect January 1,2010. On February 8, 2008, the U.S. Court of Appeals for the District ofColumbia vacated CAMR. This decision was appealed to the U.S. Supreme Courtwhich denied the appeal on February 23, 2009. The EPA has not issuedguidance to the states regarding the vacated regulation nor recommended futureactions.

 

Basedon CAMR, we installed a mercury analyzer at Asbury and installed two mercuryanalyzers at Riverton in 2008. We continue to operate the mercury analyzers atRiverton and Asbury in accordance with the appropriate state environmentalregulator’s guidance.

 

TheEPA issued an Information Collection Rule (ICR) for national emissionstandards for hazardous air pollutants for coal and oil-fired electric steamgenerating units on December 24, 2009. This ICR included our Iatan, Asburyand Riverton plants. We completed the ICR for Asbury and Riverton and submittedthem to the EPA on March 31, 2010. KCP&L will complete the Iatan ICR.The EPA ICR is a prelude for developing regulations under Section 112(r) ofthe CAA (maximum achievable emission standards) for the control of the emissionof hazardous air pollutants including mercury. The EPA is under a court orderto issue a proposed EGU MACT regulation by March 16, 2011 and to finalizethat regulation by November 16, 2011. We cannot accurately estimate thecost of the developing regulation or predict its precise timing and its impacton our operations at this time. However, absent a successful legal challenge,we expect EGU MACT regulation to ultimately require a scrubber and baghouse tobe added to our Asbury facility and may force retirement of our Rivertoncoal-fired assets or their fuel conversion to natural gas.

 

*CO**2** Emissions*

 

Ourcoal and gas plants, vehicles and other facilities, including EDG (our gassegment), emit CO2 and/or other GHGs which are measured in CarbonDioxide Equivalents (CO2e).

 

OnSeptember 22, 2009, the EPA issued the final Mandatory Reporting ofGreenhouse Gases Rule under the CAA which requires power generating andcertain other facilities, including EDG that equal or exceed an emissionthreshold of 25,000 metric tons of CO2e to report GHGs to the EPA annually. The firstrecord keeping year is 2010 with initial reporting due in March 2011. Wewill report

 

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ourGHG emissions as required to the EPA in 2011 for EDE. Submission for EDG hasbeen delayed until 2012. In addition, on September 30, 2009, the EPAissued the proposed “Prevention of Significant Deterioration and Title VGreenhouse Gases Tailoring Rule” (Tailoring Rule) that would regulate GHGemissions from emitting sources that equal or exceed a threshold of 25,000short tons of CO2e annually. TheEPA has not issued the final Tailoring Rule regulation. However, on March 28,2010, the EPA stated that regulation under the Tailoring Rule will notoccur before January 2, 2011 and that the threshold will be raisedsignificantly. The EPA indicated that Title V operating permits be the vehiclefor regulation for existing facilities with appropriate language inserted intothe permits at renewal. New units and major modifications to existing unitswould be regulated under the current Prevention of Significant Deteriorationprovisions of the CAA. On December 7, 2009, responding to a 2007 USSupreme Court decision thatdetermined that GHGs constitute “air pollutants” under the CAA, the EPAissued its final finding that GHGs threaten both the public health and thepublic welfare. This “endangerment” finding does not itself trigger any EPAregulations, but is a necessary predicate for the EPA to proceed with theTailoring Rule or other efforts to control GHGs. Several parties,including the U.S. Chamber of Commerce, have filed petitions challenging theEPA’s Endangerment Finding. In addition, when finalized, litigation of theTailoring Rule is almost certain.

 

Litigationaimed at controlling GHG emissions has also increased. For example, recentlythe U.S. Court of Appeals for the Second Circuit has ruled that certain publicand private parties can pursue claims that GHG emissions constitute a publicnuisance and can seek to recover alleged related damages. However, in March 2010,the full U.S. Court of Appeals for the Fifth Circuit overturned a similardecision by a three-judge panel and will rehear the entire case.

 

Severalproposed pieces of legislation regulating emission of GHGs, including cap andtrade systems, are under consideration by Congress with no consensus achievedto date. It is unclear what effect, if any, final federal legislation will haveon the EPA’s ability to regulate GHG emissions from stationary sources.

 

Certainstates have taken steps to develop cap and trade programs and/or otherregulatory systems which may be more stringent than any federal regulations.For example, Kansas is a participating member of the Midwestern Greenhouse GasReduction Accord (MGGRA), one purpose of which is to develop a market-based capand trade mechanism to reduce GHG emissions. The MGGRA has announced, however,that it will not issue a CO2e regulatory system pending federal legislative developments. Missouriis not a participant in the MGGRA.

 

Theultimate cost of any GHG regulations cannot be determined at this time,however, we would expect the cost of complying with any such regulations to berecoverable in our rates.

 

***Water Discharges***

 

Weoperate under the Kansas and Missouri Water Pollution Plans that wereimplemented in response to the Federal Clean Water Act (CWA). Our plants are inmaterial compliance with applicable regulations and have received necessarydischarge permits.

 

TheRiverton Plant is affected by regulations for Cooling Water Intake Structuresissued by the EPA under the CWA Section 316(b) Phase II. Theregulations became final on February 16, 2004. In accordance with theseregulations, we submitted sampling and summary reports to the Kansas Departmentof Health and Environment (KDHE) which indicate that the effect of the coolingwater intake structure on Empire Lake’s aquatic life is insignificant. In 2007the United States Court of Appeals for the Second Circuit remanded key sectionsof these CWA regulations to the EPA. As a result, the EPA suspended the regulationsand is expected to revise and re-propose the regulations by mid-2010. Under theinitial regulations, we did not expect costs associated with compliance to bematerial. We will reassess costs after the revised rules are complete.

 

*AshPonds.*

 

Weown and maintain coal ash ponds located at our Riverton and Asbury PowerPlants. Additionally, we own a 12 percent interest in a coal ash pond at theIatan Generating Station. The EPA has announced its intention to revise itswastewater effluent limitation guidelines under the CWA for coal-fired powerplants before 2012. Once the new guidelines are issued, the EPA and states

 

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wouldincorporate the new standards into wastewater discharge permits, includingpermits for coal ash ponds. We do not have sufficient information at this timeto estimate additional costs that any new standards would impose on our operations.In April and May 2009, we received Information Collection Requestsfrom the EPA regarding our ash ponds, and have responded to such requests. Allof the ash ponds are compliant with existing state and federal regulations.

 

On May 4, 2010, theEPA released its proposed new regulation pursuant to the Federal Resource Conservationand Recovery Act (RCRA) governing the management and storage of Coal CombustionResiduals (CCR). In the proposal the EPA presents two options: (1) regulationof CCR under RCRA subtitle C as a hazardous waste and (2) regulation ofCCR under RCRA subtitle D as a non-hazardous waste. We are currently performinga study to review all ash management options and their costs but have notdeveloped specific cost estimates to date. The EPA will accept comments for 90days after the proposed regulation is published in the Federal Register. It isanticipated that the final regulation will be published later this year. Weexpect compliance with the final version of either proposal to result inmaterial additional costs but would expect the cost to comply with eitherproposal or combination thereof to be recoverable in our rates.

 

***Renewable Energy***

 

Wecurrently purchase more than 15% of our energy through long-term PurchasedPower Agreements (PPAs) with Elk River Windfarm, LLC and Cloud County Windfarm,LLC. Through these PPAs, we generate about 900,000 renewable energycertificates (RECs) each year. A REC represents one megawatt-hour of renewableenergy that has been delivered into the bulk power grid and “unbundles” therenewable attributes from the associated energy. This unbundling is importantbecause it cannot be determined where the renewable energy is ultimatelydelivered once it enters the bulk power grid. As a result, RECs provide anavenue for renewable energy tracking and compliance purposes.

 

OnNovember 4, 2008, Missouri voters approved the Clean Energy Initiative(Proposition C). This initiative requires Empire and other investor-ownedutilities in Missouri to generate or purchase electricity from renewable energysources, such as solar, wind, biomass and hydro power, at the rate of at least2% of retail sales by 2011, increasing to at least 15% by 2021. Kansasestablished a renewable portfolio standard (RPS) in May 2009 and iscurrently scheduled to issue its final rulemaking by May 2010. In addition,there are several proposals currently before the U.S. Congress to adopt anationwide RPS.

 

Wehave been selling the majority of our RECs and plan to continue to sell all ora portion of them moving forward. As a result of these REC sales, we cannot claimthe underlying energy is renewable. Once a REC has been claimed or retired, itcannot be used for any other purpose. Over time, we expect to retain asufficient amount of RECs to meet any current or future RPS.

 

***Gas Segment***

 

Theacquisition of our natural gas distribution assets in June 2006 involvedthe potential future remediation of two former manufactured gas plant (FMGP)sites. FMPG Site #1 in Chillicothe, Missouri is listed in the MDNR Registry ofConfirmed Abandoned or Uncontrolled Hazardous Waste Disposal Sites in Missouri.No remediation of this site is expected to be required in the near term. Wehave received a letter stating no further action is required from the MDNR withrespect to FMPG Site #2 in Marshall, Missouri. We have incurred $0.2 million inremediation costs and estimate further remediation costs at these two sites tobe minimal.

 

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**Note 8 — Retirement Benefits**

 

Net retirement benefit 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** | ** ** |
| ** **                                  | ** ** | **2010**                              | ** ** | **2009** | ** ** | **2010** | ** ** | **2009** | ** ** | **2010** | ** ** | **2009** | ** ** |
| Service  cost                               |       | $                                     | 1,273      |   | $ | 991 |   | $ | 17 |   | $ | 16 |   | $ | 509 |   | $ | 454 |   |
| Interest  cost                              |       | 2,550                                 |       | 2,437 |   | 39 |   | 36 |   | 1,063 |   | 986 |   |
| Expected  return on plan assets             |       | (2,483                                | )          | (2,601 | ) | — |   | — |   | (966 | ) | (960 | ) |
| Amortization  of prior service cost **(1)** |       | 133                                   |       | 151 |   | (2 | ) | (2 | ) | (253 | ) | (253 | ) |
| Amortization  of net actuarial loss **(1)** |       | 1,033                                 |       | 754 |   | 32 |   | 32 |   | 344 |   | 232 |   |
| **Net periodic benefit cost**               | ** ** | **$**                                 | **2,506**  | ** ** | **$** | **1,732** | ** ** | **$** | **86** | ** ** | **$** | **82** | ** ** | **$** | **697** | ** ** | **$** | **459** | ** ** |

 
| ** **                                  | ** ** | **Twelve months ended March 31,** | ** ** |
|---------------------------------------------|------------|----------------------------------------|------------|
| ** **                                  | ** ** | **Pension**                            | ** ** | **SERP** | ** ** | **OPEB** | ** ** |
| ** **                                  | ** ** | **2010**                               | ** ** | **2009** | ** ** | **2010** | ** ** | **2009** | ** ** | **2010** | ** ** | **2009** | ** ** |
| Service  cost                               |       | $                                      | 4,894      |   | $ | 3,697 |   | $ | 62 |   | $ | 61 |   | $ | 1,885 |   | $ | 1,698 |   |
| Interest  cost                              |       | 9,989                                  |       | 9,240 |   | 150 |   | 142 |   | 3,984 |   | 3,692 |   |
| Expected  return on plan assets             |       | (10,261                                | )          | (10,651 | ) | — |   | — |   | (3,849 | ) | (3,772 | ) |
| Amortization  of prior service cost **(1)** |       | 586                                    |       | 709 |   | (8 | ) | (8 | ) | (1,011 | ) | (1,011 | ) |
| Amortization  of net actuarial loss **(1)** |       | 3,461                                  |       | 2,043 |   | 103 |   | 133 |   | 981 |   | 604 |   |
| **Net periodic benefit cost**               | ** ** | **$**                                  | **8,669**  | ** ** | **$** | **5,038** | ** ** | **$** | **307** | ** ** | **$** | **328** | ** ** | **$** | **1,990** | ** ** | **$** | **1,211** | ** ** |

 

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(1) Amountsare amortized from our regulatory asset originally recorded upon recognizingour net pension liability on the balance sheet.

 

Annualcontributions to our pension plans are at least equal to the minimum fundingrequirements of ERISA. Beginning in 2010, we will also be required to fund atleast our actuarial cost, which we estimate at $12.0 million. The actualminimum funding requirements will be determined based on the results of theactuarial valuations and, in the case of 2011, the performance of our pensionassets during 2010. Our OPEB funding policy is to contribute annually an amountat least equal to the actuarial cost of postretirement benefits. We expect tobe required to fundapproximately$3.2 million in 2010.

 

SeeNote 12 — Income Taxes for information regarding the effect of the PatientProtection and Affordable Care Act that was enacted on March 23, 2010.

 

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

 

Ourperformance based restricted stock awards, stock options and their relateddividend equivalents are classified as liability awards, in accordance withfair value guidelines. Awards treated as liability instruments are revaluedeach period until settled, and cost is accrued over the requisite serviceperiod and adjusted to fair value at each reporting period until settlement orexpiration of the award.

 

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

 
| ** **                 | ** ** | **Three Months Ended** | ** ** | **Twelve Months Ended** | ** ** |
|----------------------------|------------|------------------------|------------|-------------------------|------------|
| ** **                 | ** ** | **2010**               | ** ** | **2009**                | ** ** | **2010** | ** ** | **2009** | ** ** |
| ** **                 |       |                   |       |                    |       |   |   |   |   |
| **Compensation expense**   |       | $                      | 798        |                    | $          | 580 |   | $ | 2,510 |   | $ | 1,546 |   |
| **Tax benefit recognized** |       | 288                    |       | 209                     |       | 898 |   | 544 |   |
|                            |            |                        |            |                         |            |  |  |  |  |  |  |  |  |

 

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Activityfor our various stock plans for the three months ended March 31, 2010, issummarized below:

 

**Performance-BasedRestricted Stock Awards**

 

Performance-based restrictedstock awards are granted to qualified individuals consisting of the right toreceive a number of shares of common stock at the end of the restricted periodassuming performance criteria are met. The fair value of the outstandingrestricted stock awards was estimated using a Monte Carlo option valuationmodel. The assumptions used in the model for each grant year are noted in thefollowing table:

 
| ** **                               | ** ** | **Fair Value of Grants Outstanding at March 31,** | ** ** |
|------------------------------------------|------------|--------------------------------------------------------|------------|
| ** **                               | ** ** | **2010**                                               | ** ** | **2009** | ** ** |
| Risk-free  interest rate                 |       | 0.32% to 1.45%                                         |       | 0.50% to 1.08% |   |
| Expected  volatility of Empire stock     |       | 28.6%                                                  |       | 28.5% |   |
| Expected  volatility of peer group stock |       | 22.2% to 81.5%                                         |       | 21.6% to 75.5% |   |
| Expected  dividend yield on Empire stock |       | 7.3%                                                   |       | 6.8% |   |
| Expected  forfeiture rates               |       | 3%                                                     |       | 3% |   |
| Plan  cycle                              |       | 3 years                                                |       | 3 years |   |
| Fair  value percentage                   |       | 104.0% to 125.0%                                       |       | 91.0% to 102.0% |   |
| Weighted  average fair value per share   |       | $20.76                                                 |       | $15.08 |   |

 

Non-vested restricted stockawards (based on target number) as of March 31, 2010 and 2009 and changesduring the three months ended March 31, 2010 and 2009 were as follows:

 
| ** **                         | ** ** | **2010**              | ** ** | **2009**                               | ** ** |
|------------------------------------|------------|-----------------------|------------|----------------------------------------|------------|
| ** **                         | ** ** | **Number of  shares** | ** ** | **Weighted Average  Grant Date Price** | ** ** | **Number of  shares** | ** ** | **Weighted Average  Grant Date Price** | ** ** |
|                               |       |                  |       |                                   |       |   |   |   |   |
| **Outstanding at January 1,** |       | 52,200                |       | $                                      | 21.57      |   | 52,300 |   | $ | 22.64 |   |
| **Granted**                        |       | 13,000                |       | $                                      | 18.36      |   | 13,500 |   | $ | 18.12 |   |
| **Awarded**                        |       | (15,104               | )          | $                                      | 23.81      |   | (12,394 | ) | $ | 22.23 |   |
| **Not Awarded**                    |       | (2,596                | )          | —                                 |       | (1,206 | ) | — |   |
| ** **                         |       |                  |       |                                   |       |   |   |   |   |
| **Nonvested at March 31,**    |       | 47,500                |       | $                                      | 19.86      |   | 52,200 |   | $ | 21.57 |   |

 

At March 31, 2010,there was $0.5 million of total unrecognized compensation cost related toestimated outstanding awards. This cost will be recognized over the outstandingyears remaining in the vesting period.

 

**StockOptions**

 

Stockoption grants vest upon satisfaction of service conditions. The cost of theawards is generally recognized over the requisite (explicit) service period.The fair value of the outstanding options was estimated as of March 31,2010 and 2009, under a Black-Scholes methodology. The assumptions used in thevaluations are shown below:

 
| ** **                                 | ** ** | **Fair Value of Grants Outstanding at March 31,** | ** ** |
|--------------------------------------------|------------|--------------------------------------------------------|------------|
| ** **                                 | ** ** | **2010**                                               | ** ** | **2009** | ** ** |
| **Risk-free interest rate**                |       | 0.91% to 1.85%                                         |       | 0.99% to 2.08% |   |
| **Dividend yield**                         |       | 7.3%                                                   |       | 6.8% |   |
| **Expected volatility**                    |       | 23.0%                                                  |       | 24.0% |   |
| **Expected life in months**                |       | 78                                                     |       | 78 |   |
| **Market value**                           |       | $18.02                                                 |       | $14.44 |   |
| **Weighted average fair value per option** |       | $0.85                                                  |       | $0.35 |   |

 

Asummary of option activity under the plan during the three months ended March 31,2010 and 2009 is presented below:

 

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| ** **                         | ** ** | **2010**    | ** ** | **2009**              | ** ** |
|------------------------------------|------------|-------------|------------|-----------------------|------------|
| ** **                         | ** ** | ** **  | ** ** | **Weighted  Average** | ** ** | ** ** | ** ** | **Weighted  Average** | ** ** |
| ** **                         | ** ** | **Options** | ** ** | **Exercise Price**    | ** ** | **Options** | ** ** | **Exercise Price** | ** ** |
| **Outstanding at January 1,** |       | 232,600     |       | $                     | 22.19      |   | 205,600 |   | $ | 22.73 |   |
| **Granted**                        |       | 34,800      |       | $                     | 18.36      |   | 27,000 |   | $ | 18.12 |   |
| **Exercised**                      |       | —      |       | —                |       | — |   | — |   |
| **Outstanding at March 31,**  |       | 267,400     |       | $                     | 21.69      |   | 232,600 |   | $ | 22.19 |   |
| **Exercisable at March 31,**  |       | 149,200     |       | $                     | 23.04      |   | 85,000 |   | $ | 22.46 |   |

 

Theaggregate intrinsic value at March 31, 2010 and 2009 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, 2010 was$18.12 to $23.81. The weighted-average remaining contractual life ofoutstanding options at March 31, 2010 and 2009 was 7.3 years and 7.3years, respectively. As of March 31, 2010, there was $0.3 million of totalunrecognized compensation expense related to the non-vested options and relateddividend equivalents granted under the plan. That cost will be recognized overa 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 income (in thousands) for all periods presented ended March 31:

 
| ** **                                        | ** ** | **Three Months  Ended** | ** ** | **Three Months  Ended** | ** ** | **Twelve Months********Ended** | ** ** | **Twelve Months********Ended** | ** ** |
|---------------------------------------------------|------------|-------------------------|------------|-------------------------|------------|--------------------------------|------------|--------------------------------|------------|
| ** **                                        | ** ** | **2010**                | ** ** | **2009**                | ** ** | **2010**                       | ** ** | **2009**                       | ** ** |
| Electric transmission and distribution expense    |       | $                       | 2,827      |                    | $          | 2,590                          |       | $                              | 11,300     |   | $ | 10,824 |   |
| Natural gas transmission and distribution expense |       | 532                     |       | 526                     |       | 2,167                          |       | 2,047                          |       |
| Power operation expense (other than fuel)         |       | 2,904                   |       | 3,064                   |       | 12,156                         |       | 12,022                         |       |
| Customer accounts and assistance expense          |       | 2,919                   |       | 2,451                   |       | 11,065                         |       | 10,069                         |       |
| Employee pension expense (1)                      |       | 1,464                   |       | 1,360                   |       | 5,661                          |       | 5,698                          |       |
| Employee healthcare plan (1)                      |       | 1,550                   |       | 1,317                   |       | 6,142                          |       | 6,510                          |       |
| General office supplies and expense               |       | 2,676                   |       | 2,260                   |       | 10,485                         |       | 9,148                          |       |
| Administrative and general expense                |       | 3,416                   |       | 2,999                   |       | 12,628                         |       | 11,768                         |       |
| Allowance for uncollectible accounts              |       | 600                     |       | 947                     |       | 2,778                          |       | 3,320                          |       |
| Miscellaneous expense                             |       | 29                      |       | (12                     | )          | 120                            |       | 116                            |       |
| Total                                             |       | $                       | 18,917     |                    | $          | 17,502                         |       | $                              | 74,502     |   | $ | 71,522 |   |

 

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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 asthree segments:  electric, gas and other.As part of our electric segment, we also provide water service to three townsin Missouri. The other segment consists of our fiber optics business.

 

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

 

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| ** **                              | ** ** | **For the quarter ended March 31,** | ** ** |
|-----------------------------------------|------------|------------------------------------------|------------|
| ** **                              | ** ** | **2010**                                 | ** ** |
| **($-000’s)**                      | ** ** | **Electric**                             | ** ** | **Gas** | ** ** | **Other** | ** ** | **Eliminations** | ** ** | **Total** | ** ** |
| ** **                              |       |                                     |       |   |   |   |   |   |   |   |   |
| **Statement of Operations Information** |       |                                     |       |   |   |   |   |   |   |   |   |
| Revenues                                |       | $                                        | 114,033    |   | $ | 24,560 |   | $ | 1,449 |   | $ | (149 | ) | $ | 139,893 |   |
| Depreciation  and amortization          |       | 12,301                                   |       | 509 |   | 375 |   | — |   | 13,185 |   |
| Federal  and state income taxes         |       | 8,281                                    |       | 1,440 |   | 214 |   | — |   | 9,935 |   |
| Operating  income                       |       | 12,485                                   |       | 3,235 |   | 358 |   | — |   | 16,078 |   |
| Interest  income                        |       | 72                                       |       | 126 |   | — |   | (128 | ) | 70 |   |
| Interest  expense                       |       | 10,559                                   |       | 983 |   | 10 |   | (128 | ) | 11,424 |   |
| Income  from AFUDC (debt and equity)    |       | 4,155                                    |       | — |   | — |   | — |   | 4,155 |   |
| Net  income                             |       | 5,924                                    |       | 2,314 |   | 348 |   | — |   | 8,586 |   |
| ** **                              |       |                                     |       |   |   |   |   |   |   |   |   |
| **Capital Expenditures**                |       | $                                        | 29,236     |   | $ | 288 |   | $ | 1,351 |   | $ | — |   | $ | 30,875 |   |

 
| ** **                              | ** ** | **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 |   |

 
| ** **                              | ** ** | **For the twelve months ended March 31,** | ** ** |
|-----------------------------------------|------------|------------------------------------------------|------------|
| ** **                              | ** ** | **2010**                                       | ** ** |
| **($-000’s)**                      | ** ** | **Electric**                                   | ** ** | **Gas** | ** ** | **Other** | ** ** | **Eliminations** | ** ** | **Total** | ** ** |
| ** **                              |       |                                           |       |   |   |   |   |   |   |   |   |
| **Statement of Operations Information** |       |                                           |       |   |   |   |   |   |   |   |   |
| Revenues                                |       | $                                              | 442,142    |   | $ | 53,787 |   | $ | 5,709 |   | $ | (592 | ) | $ | 501,046 |   |
| Depreciation  and amortization          |       | 48,507                                         |       | 2,024 |   | 1,475 |   | — |   | 52,006 |   |
| Federal  and state income taxes         |       | 22,394                                         |       | 969 |   | 845 |   | — |   | 24,208 |   |
| Operating  income                       |       | 65,202                                         |       | 5,254 |   | 1,462 |   | — |   | 71,918 |   |
| Interest  income                        |       | 222                                            |       | 371 |   | — |   | (382 | ) | 211 |   |
| Interest  expense                       |       | 43,174                                         |       | 3,946 |   | 41 |   | (382 | ) | 46,779 |   |
| Income  from AFUDC (debt and equity)    |       | 14,683                                         |       | 1 |   | — |   | — |   | 14,684 |   |
| Net  income                             |       | 36,158                                         |       | 1,436 |   | 1,374 |   | — |   | 38,968 |   |
| ** **                              |       |                                           |       |   |   |   |   |   |   |   |   |
| **Capital Expenditures**                |       | $                                              | 145,684    |   | $ | 2,074 |   | $ | 2,069 |   | $ | — |   | $ | 149,827 |   |

 

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| ** **                              | ** ** | **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 |   |
| Income  from continuing operations      |       | 41,921                                         |       | 975 |   | 750 |   | — |   | 43,646 |   |
| ** **                              |       |                                           |       |   |   |   |   |   |   |   |   |
| **Capital Expenditures**                |       | $                                              | 200,467    |   | $ | 2,183 |   | $ | 2,082 |   | $ | — |   | $ | 204,732 |   |

 
| ** **                    | ** ** | **As of March 31, 2010** | ** ** |
|-------------------------------|------------|-------------------------------|------------|
| **($-000’s)**            | ** ** | **Electric**                  | ** ** | **Gas(1)** | ** ** | **Other** | ** ** | **Eliminations** | ** ** | **Total** | ** ** |
| **Balance Sheet Information** |       |                          |       |   |   |   |   |   |   |   |   |
| Total assets                  |       | $                             | 1,771,517  |   | $ | 139,236 |   | $ | 22,830 |   | $ | (85,972 | ) | $ | 1,847,611 |   |
|                               |            |                               |            |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

----

(1) Includesgoodwill of $39,492.

 
| ** **                    | ** ** | **As of December 31, 2009** | ** ** |
|-------------------------------|------------|----------------------------------|------------|
| **($-000’s)**            | ** ** | **Electric**                     | ** ** | **Gas(1)** | ** ** | **Other** | ** ** | **Eliminations** | ** ** | **Total** | ** ** |
| **Balance Sheet Information** |       |                             |       |   |   |   |   |   |   |   |   |
| Total assets                  |       | $                                | 1,759,415  |   | $ | 134,355 |   | $ | 21,907 |   | $ | (75,831 | ) | $ | 1,839,846 |   |
|                               |            |                                  |            |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

----

(1) Includesgoodwill of $39,492.

 

**Note 12—Income Taxes**

 

Thefollowing table shows our consolidated effective federal and state income taxrates for the applicable periods ended March 31, 2010:

 
| ** **                                                 | ** ** | **Three Months Ended** | ** ** | **Twelve Months Ended** | ** ** |
|------------------------------------------------------------|------------|------------------------|------------|-------------------------|------------|
| ** **                                                 | ** ** | **2010**               | ** ** | **2009**                | ** ** | **2010** | ** ** | **2009** | ** ** |
| Consolidated  effective federal and state income tax rates |       | 53.6                   | %          | 33.9                    | %          | 38.3 | % | 33.1 | % |

 

The effective tax rates for the first quarter of 2010 and the twelvemonths ended March 31, 2010 are higher than comparable year periodsprimarily due to the new health care legislation. On March 23, 2010, thePatient Protection and Affordable Care Act became law. This legislationincludes a provision that reduces the deductibility, for income tax purposes,of retiree healthcare costs to the extent an employer receives federalsubsidies. Companies receive the subsidy when they provide retiree prescriptionbenefits at least equivalent to Medicare Part D coverage in theirpostretirement healthcare plan. Although the elimination of this tax benefitdoes not take effect until 2013, this change requires us to recognize the fullaccounting impact in our financial statements in the period in which the legislationis enacted. As a result, in the first quarter of 2010, we recorded a one-timenon-cash charge of approximately $2.1 million to income taxes to reflect theimpact of this change. Our 2010 effective tax rate also increased due to theadditional tax expense associated with the current year retiree health careaccruals.

 

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As part of an agreementreached in our current Missouri electric rate case, we have also agreed tocommence an eighteen year amortization of a deferred asset related to the taxbenefits of cost of removal. These tax benefits were flowed through tocustomers from 1981-2008 and totaled approximately $11.1 million. We recorded aregulatory asset expecting to recover these benefits from customers in futureperiods. We estimated the portion of the amortization period where raterecovery would no longer be probable for this item and wrote off approximately$1.2 million. Amortization of the remaining regulatory tax asset will begin in2012, which is also when we expect to be able to request rate recovery of theasset.

 

We do not expect anysignificant changes to our unrecognized tax benefits over the next twelvemonths. The reserve balance related to unrecognized tax benefits as of December 31,2009 was $906,000 and has not materially changed at March 31, 2010.

 

Ourconsolidated provision for income taxes increased approximately $4.4 millionduring the first quarter of 2010 as compared to the same period in 2009 mainlydue to the two non-cash charges noted above. Our consolidated provision forincome taxes increased approximately $2.4 million during the twelve monthsended March 31, 2010 as compared to the twelve months ended March 31,2009.

 

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

 

**EXECUTIVE SUMMARY**

 

We operate our businesses as three segments: electric, gas and other.The****Empire District Electric Company (EDE)is an operating public utility engaged in the generation, purchase,transmission, distribution and sale of electricity in parts of Missouri,Kansas, Oklahoma and Arkansas. As part of our electric segment, we also providewater service to three towns in Missouri. The Empire District Gas Company (EDG)is our wholly owned subsidiary. It provides natural gas distribution tocustomers in 44 communities in northwest, north central and west centralMissouri. Our other segment consists of our fiber optics business. During thetwelve months ended March 31, 2010, 88.3% of our gross operating revenueswere provided from sales from our electric segment (including 0.4% from thesale of water), 10.7% from our gas segment and 1.0% from our other segment.

 

***Earnings***

 

During the first quarter of2010, basic and diluted earnings per weighted average share of common stockwere $0.22 as compared to $0.32 in the first quarter of 2009. For the twelvemonths ended March 31, 2010, basic and diluted earnings per weighted averageshare of common stock were $1.08 as compared to $1.29 for the twelve monthsended March 31, 2009. The primary negative driver for the first quarter of2010 was increased income taxes, primarily due to the two non-cash charges inthe first quarter of 2010 discussed below and the dilutive effect of additionalshares issued. The primary positive driver for the first quarter of 2010 wasincreased electric revenues resulting from increased demand in the firstquarter of 2010 due to favorable weather. The primary negative drivers for thetwelve months ended March 31, 2010 were increased income taxes, primarilydue to the two non-cash charges in the first quarter of 2010, increasedoperations and maintenance expenses, interest charges and the dilutive effectof additional shares issued. The primary positive driver, which partly offsetthese decreases, was increased electric on-system revenues.

 

The table below sets forth areconciliation of basic and diluted earnings per share between the three monthsand twelve months ended March 31, 2009 and March 31, 2010, which is anon-GAAP presentation. The economic substance behind our non-GAAP earning pershare (EPS) measure is to present the after tax impact of significant items andcomponents of the statement of income on a per share basis before the impact ofadditional stock issuances.

 

We believe this presentationis useful to investors because the statement of income does not readily showthe EPS impact of the various components, including the effect of new stock issuances.This could limit the readers’ understanding of the reasons for the EPS changefrom the previous year’s EPS. This information is useful to management, and webelieve this information is useful to

 

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investors, to better understand the reasons for the fluctuation in EPSbetween the prior and current years on a per share basis.

 

This reconciliation may notbe comparable to other companies or more useful than the GAAP presentationincluded in the statement of income. We also note that this presentation doesnot purport to be an alternative to earnings per share determined in accordancewith GAAP as a measure of operating performance or any other measure offinancial performance presented in accordance with GAAP. Management compensatesfor the limitations of using non-GAAP financial measures by using them tosupplement GAAP results to provide a more complete understanding of the factorsand trends affecting the business than GAAP results alone.

 
| ** **                                   | ** ** | **Three Months  Ended** | ** ** | **Twelve Months  Ended** | ** ** |
|----------------------------------------------|------------|------------------------------|------------|-------------------------------|------------|
| **Earnings Per Share — 2009**           | ** ** | **$**                        | **0.32**   | ** **                    | **$**      | **1.29** | ** ** |
| ** **                                   |       |                         |       |                          |       |
| **Revenues**                                 |       |                         |       |                          |       |
| Electric  on-system                          |       | $                            | 0.10       |                          | $          | 0.11 |   |
| Electric  off — system and other        |       | 0.04                         |       | (0.19                         | )          |
| Gas                                          |       | (0.07                        | )          | (0.24                         | )          |
| Water                                        |       | 0.00                         |       | 0.00                          |       |
| Other                                        |       | 0.00                         |       | 0.01                          |       |
| **Expenses**                                 | ** ** | ** **                   | ** ** | ** **                    | ** ** |
| Electric  fuel and purchased power           |       | (0.07                        | )          | 0.15                          |       |
| Cost  of natural gas sold and transported    |       | 0.08                         |       | 0.25                          |       |
| Regulated  — electric segment           |       | (0.03                        | )          | (0.07                         | )          |
| Regulated  —gas segment                 |       | 0.00                         |       | 0.01                          |       |
| Maintenance  and repairs                     |       | 0.00                         |       | (0.05                         | )          |
| Depreciation  and amortization               |       | (0.01                        | )          | 0.01                          |       |
| Other  taxes                                 |       | (0.01                        | )          | (0.01                         | )          |
| Interest  charges                            |       | 0.00                         |       | (0.04                         | )          |
| AFUDC                                        |       | 0.01                         |       | 0.02                          |       |
| Change  in effective income tax rates        |       | (0.10                        | )          | (0.09                         | )          |
| Other  income and deductions                 |       | (0.01                        | )          | (0.03                         | )          |
| Dilutive  effect of additional shares issued |       | (0.03                        | )          | (0.05                         | )          |
| **Earnings Per Share — 2010**           | ** ** | **$**                        | **0.22**   | ** **                    | **$**      | **1.08** | ** ** |

 

**RecentActivities**

 

***Healthcare Reform Act - Medicare Part Dbenefits***

 

On March 23, 2010, the Patient Protection and Affordable Care Actbecame law. This legislation includes a provision that reduces thedeductibility, for income tax purposes, of retiree healthcare costs to theextent an employer receives federal subsidies. Companies receive the subsidy whenthey provide retiree prescription benefits at least equivalent to Medicare Part Dcoverage in their postretirement healthcare plan. Although the elimination ofthis tax benefit does not take effect until 2013, this change requires us torecognize the full accounting impact in our financial statements in the periodin which the legislation is enacted. As a result, in the first quarter of 2010,we recorded a one-time non-cash charge of approximately $2.1 million to reflectthe impact of this change. Our 2010 effective tax rate also increased due tothe additional tax expense associated with the current year retiree health careaccruals. See Note 12 of “Notes to Consolidated Financial Statements.”

 

***Regulatory Matters***

 

OnApril 30, 2010, the parties in our current Missouri electric rate casefiled on October 29, 2009, filed a pleading with the MPSC stating that wehave reached an agreement in principle as to all issues in the case. We expectthe agreement to be filed sometime in May 2010.

 

As part of an earlier agreement reached in this current Missourielectric rate case, we agreed to commence an eighteen year amortization of adeferred asset related to the tax benefits of cost of removal. These taxbenefits were flowed through to customers from 1981 to 2008 and totaled

 

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approximately$11.1 million. We had previously recorded a regulatory asset expecting torecover these benefits from customers in future periods. We estimated theportion of the amortization period where rate recovery would no longer beprobable for this item and wrote off approximately $1.2 million. Amortizationof the remaining regulatory tax asset will begin in 2012, which is also when weexpect to be able to request rate recovery of the asset. See Note 12 of “Notesto Consolidated Financial Statements”.

 

As a result of the delay in the Iatan 2 project, we have also agreednot to seek a permanent increase in the current rate case for any costsassociated with the Iatan 2 unit with the exception of that portion of theIatan 2 common plant needed to operate Iatan 1. We anticipate filing a ratecase at the conclusion of this case to recover the Iatan 2 costs. We have alsoagreed to the use of construction accounting for our Plum Point project such aswe use for our Iatan 2 project. Construction accounting allows us to defercertain charges as regulatory assets, including depreciation, operatingexpenses and carrying costs related to operation of the facilities until thefacilities are ultimately included in our rate base. See Note 7 of “Notes toConsolidated Financial Statements.”

 

On November 4, 2009, we filed a request with the KCC for an annualincrease in base rates for our Kansas electric customers in the amount of $5.2million, or 24.6%. This request is primarily to allow us to recover capitalexpenditures associated with environmental upgrades at Iatan 1 completed in2009 and at our Asbury plant completed in 2008 and our investment in newgenerating units at Iatan 2, the Plum Point Generating Station and our Riverton12 unit that went on line in 2007. On May 4, 2010, we filed a stipulationwith the parties to this rate case, pending KCC approval. We anticipate newrates will go into effect in July 2010.

 

OnMarch 25, 2010, we requested a capital cost recovery rider (CCRR) at theOklahoma Corporation Commission (OCC). The rider is designed to recover thecarrying costs on our capital investment for generation, transmission anddistribution assets that have been added to the system since our last Oklahomageneral rate case (May 2003), as well as investments made on an ongoingbasis. As requested, the operation of the CCRR would increase our operatingrevenue in Oklahoma in a series of three steps to be followed with a generalrate case in 2011. If the CCRR is authorized by the OCC, it is expected toresult in a maximum overall increase in Oklahoma revenues of approximately $3million pre-tax, or approximately 33%.

 

OnMarch 12, 2010, we filed Generation Formula Rate (GFR) tariffs with theFERC which will be utilized for our wholesale customers. New rates based on theGFR tariffs are expected to be effective around August 1, 2010.

 

OnJune 5, 2009, we filed a request with the MPSC for an annual increase inbase rates for our Missouri gas customers in the amount of $2.9 million, or4.9%. In this filing, we requested recovery of the ongoing cost of operatingand maintaining our 1,200-mile gas distribution system and a return on equityof 11.3%. On February 24, 2010, the MPSC unanimously approved an agreementamong the Office of the Public Counsel (OPC), the MPSC staff and us for anincrease of $2.6 million. Pursuant to the agreement, new rates went into effecton April 1, 2010.

 

OnMay 13, 2009, the OPC filed a petition in the Jasper County Circuit Courtseeking refunds with regard to utility rates for electric service paid by ourMissouri customers during the period of January 1, 2007 to December 13,2007. During this period, we charged the rates set forth in the tariffs whichwere approved by, and are on file with, the MPSC. We filed a motion to dismiss,or, in the alternative, motion for more definitive statement. On September 3,2009, the Jasper County Circuit Court granted our motion and dismissed the OPC’spetition with prejudice. On October 7, 2009, the OPC appealed the JasperCounty Circuit Court decision to the Missouri Court of Appeals. The MissouriCourt of Appeals issued its opinion on March 31, 2010, affirming thejudgment of the Jasper County Circuit Court and holding that the OPC lacks thestatutory authority to bring a civil action against us for refunds on behalf ofour customers. The Mandate of the Missouri Court of Appeals was issued on April 16,2010, ending the case and all appeals.

 

For additional information, see “Rate Matters”below.

 

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***Iatan 2 Coal Investment Tax Credits***

 

A December 2009 awardfrom an arbitration panel ordered KCP&L to renegotiate with the IRS aprevious $125 million advanced coal investment tax credit granted its Iatan 2plant. The arbitration panel agreed that we should have received our 12% shareof the credit as 12% owners of Iatan 2. The arbitration panel ruled that if theIRS does not grant us our 12% share of the credit, worth approximately $17.7million, then KCP&L must pay us the difference. On March 30, 2010,KCP&L filed a federal lawsuit seeking to vacate the arbitration award onthe grounds that the arbitration panel exceeded its authority. We filed amotion to dismiss on the grounds that the court lacks jurisdiction over thissuit. We cannot predict the outcome of the lawsuit nor the timing of thereceipt of the credit should the lawsuit be decided in our favor. However, itwould have no significant income statement impact as the credit, which wouldreduce our tax payments, would flow to our customers over the life of theplant.

 

***Ozark Beach Plant***

 

Ourhydroelectric generating plant (FERC Project No. 2221), located on theWhite River at Ozark Beach, Missouri, has a generating capacity of 16megawatts. We have a long-term license from FERC to operate this plant whichforms Lake Taneycomo in southwestern Missouri. As part of the Energy and WaterDevelopment Appropriations Act of 2006 (the Appropriations Act), a new minimumflow was established with the intent of increasing minimum flows onrecreational streams in Arkansas. To accomplish this, the level of Bull ShoalsLake will be increased an average of 5 feet. The increase at Bull Shoals willdecrease the head waters available for generation at Ozark Beach by 5 feet and,thus, reduce our electrical output. We estimate the lost production to be up to16% of our average annual energy production for this unit. The loss in thisfacility would require us to replace it with additional generation from ourgas-fired and coal-fired units or with purchased power. The Appropriations Actrequires the Southwest Power Administration (SWPA), in coordination with us andour relevant public service commissions, to determine our economic detriment.

 

TheSWPA published its Final Determination Report on January 23, 2009documenting the procedure they intended to use to calculate the present valueof the future lifetime replacement cost of the electrical energy and capacitylost due to the White River Minimum Flows project at Ozark Beach. The actualhydropower compensation values were to be calculated using the method presentedin the Final Determination and current values for the specified parametersbased on the official implementation date. Assuming a January 1, 2011 dateof implementation for the White River Minimum Flows project and November 2008values for the specified parameters, the SWPA’s determination at that timeresulted in a present value for the estimated future lifetime replacement costsof the electrical energy and capacity at Ozark Beach of $41.3 million. On June 8,2009, the SWPA published a draft addendum to its January 2009 FinalDetermination Report documenting proposed changes to the SWPA’s methodology,including the inclusion of an additional discount rate source to be used by theSWPA in determination of the present value of the losses. Assuming a January 1,2011 date of implementation for the White River Minimum Flows project andcurrent values for the specified parameters, the SWPA’s Draft Addendum to itsFinal Determination results in a present value of $22.3 million for theestimated future lifetime replacement costs of the electrical energy andcapacity at Ozark Beach. We and the MPSC have provided comments on the new methodologyincluded in the draft addendum but cannot predict the final outcome.Originally, the Appropriations Act had a provision for the Army Corp ofEngineers to provide a one time payment to us for lost energy production. Thisprovision was revised in October 2009 to allow the SWPA to pay for damagesthrough a special disbursement account. Under the revised law, payments must bemade annually by SWPA in an amount of at least $5 million until the totaldamages are reimbursed.We have been informed that SWPA intends to make a payment of at least$5 million by September 30, 2010.

 

***Financings***

 

Duringthe first quarter of 2010, we issued and sold 1,678,341 shares of our commonstock, pursuant to our $120 million equity distribution agreement with UBSSecurities LLC (UBS), at an average price per share of $18.27, resulting inproceeds to us of approximately $29.7 million (after

 

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paymentof approximately $0.9 million in commissions to the sales agent). Sinceinception of the program, in the aggregate, we have issued and sold 5,479,863shares pursuant to the program, resulting in net proceeds to us ofapproximately $96.9 million.

 

**RESULTS OF OPERATIONS**

 

The following discussion analyzes significant changes in the results ofoperations for the three-month and twelve-month periods ended March 31,2010, compared to the same periods ended March 31, 2009.

 

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** | ** ** |
|------------|------------|------------------------|------------|-------------------------|------------|
| ** ** | ** ** | **2010**               | ** ** | **2009**                | ** ** | **2010** | ** ** | **2009** | ** ** |
|       |       |                   |       |                    |       |   |   |   |   |
| Electric   |       | $                      | 5.9        |                    | $          | 8.8 |   | $ | 36.2 |   | $ | 41.9 |   |
| Gas        |       | 2.3                    |       | 1.8                     |       | 1.4 |   | 1.0 |   |
| Other      |       | 0.4                    |       | 0.3                     |       | 1.4 |   | 0.8 |   |
| Net income |       | $                      | 8.6        |                    | $          | 10.9 |   | $ | 39.0 |   | $ | 43.7 |   |

 

***Electric Segment***

 

**Overview**

 

Our electric segment income for the first quarter of 2010 was $5.9million as compared to $8.8 million for the first quarter of 2009, a decrease of$2.9 million, primarily due to the non-cash charges relating to deferred taxesin the first quarter of 2010 discussed above. As a result, our effective incometax rate for the 2010 first quarter was approximately 54% compared to 34% inthe 2009 period. Excluding these non-cash charges, the effective tax rate inthe 2010 first quarter would have been 36%.

 

Electric operating revenues comprisedapproximately 81.5% of our total operating revenues during the first quarter of2010. Of our total electric operating revenues during the first quarter of2010, approximately 47.5% were from residential customers, 26.2% fromcommercial customers, 12.4% from industrial customers, 4.4% from wholesaleon-system customers, 5.5% from wholesale off-system transactions, 2.5% fromother electric revenues, primarily public authorities and 1.5% frommiscellaneous sources. The percentage of revenues provided from our wholesaleoff-system transactions increased during the first quarter of 2010 as comparedto the first quarter of 2009 primarily due to increased market demand resultingfrom colder weather in the first quarter of 2010 as compared to the firstquarter of 2009.

 

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)** | ** ** |
|------------------------|------------|------------------------------------|------------|
| **Customer  Class**    | ** ** | **First  Quarter  2010**           | ** ** | **First  Quarter  2009** | ** ** | **%  Change*** | ** ** | **12 Months  Ended  2010** | ** ** | **12 Months  Ended  2009** | ** ** | **%  Change*** | ** ** |
| Residential            |       | 639.2                              |       | 550.9 |   | 16.0 | % | 1,954.8 |   | 1,910.3 |   | 2.3 | % |
| Commercial             |       | 385.7                              |       | 376.0 |   | 2.6 |   | 1,589.5 |   | 1,619.1 |   | (1.8 | ) |
| Industrial             |       | 231.0                              |       | 240.2 |   | (3.8 | ) | 982.9 |   | 1,051.5 |   | (6.5 | ) |
| Wholesale on-system    |       | 84.9                               |       | 80.8 |   | 5.1 |   | 336.2 |   | 339.9 |   | (1.1 | ) |
| Other**                |       | 33.9                               |       | 32.2 |   | 5.2 |   | 125.1 |   | 123.9 |   | 0.9 |   |
| Total  on-system sales |       | 1,374.7                            |       | 1,280.1 |   | 7.4 |   | 4,988.5 |   | 5,044.7 |   | (1.1 | ) |
| Off-system             |       | 182.5                              |       | 133.9 |   | 36.4 |   | 564.6 |   | 681.7 |   | (17.2 | ) |
| Total kWh Sales        |       | 1,557.2                            |       | 1,414.0 |   | 10.1 |   | 5,553.1 |   | 5,726.4 |   | (3.0 | ) |

 

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**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)** | ** ** |
|-------------------------------------------|------------|--------------------------------------------------------------|------------|
| **Customer  Class**                       | ** ** | **First  Quarter  2010**                                     | ** ** | **First  Quarter  2009** | ** ** | **%  Change*** | ** ** | **12  Months  Ended  2010** | ** ** | **12  Months  Ended  2009** | ** ** | **%  Change*** | ** ** |
| Residential                               |       | $                                                            | 54.0       |   | $ | 48.6 |   | 11.1 | % | $ | 185.8 |   | $ | 179.2 |   | 3.7 | % |
| Commercial                                |       | 29.7                                                         |       | 29.7 |   | 0.3 |   | 135.9 |   | 134.6 |   | 0.9 |   |
| Industrial                                |       | 14.1                                                         |       | 14.9 |   | (5.3 | ) | 65.2 |   | 67.4 |   | (3.3 | ) |
| Wholesale on-system                       |       | 4.9                                                          |       | 4.7 |   | 5.1 |   | 18.4 |   | 18.9 |   | (2.2 | ) |
| Other**                                   |       | 2.9                                                          |       | 2.7 |   | 3.8 |   | 11.7 |   | 11.2 |   | 4.2 |   |
| Total on-system revenues                  |       | $                                                            | 105.6      |   | $ | 100.6 |   | 5.0 |   | $ | 417.0 |   | $ | 411.3 |   | 1.4 |   |
| Off-system                                |       | 6.2                                                          |       | 4.0 |   | 56.9 |   | 16.6 |   | 26.2 |   | (36.6 | ) |
| Total Revenues from kWh Sales             |       | 111.8                                                        |       | 104.6 |   | 7.0 |   | 433.6 |   | 437.5 |   | (0.9 | ) |
| Miscellaneous Revenues***                 |       | 1.8                                                          |       | 1.8 |   | (2.1 | ) | 6.8 |   | 7.0 |   | (2.7 | ) |
| Total Electric Operating Revenues         |       | $                                                            | 113.6      |   | $ | 106.4 |   | 6.8 |   | $ | 440.4 |   | $ | 444.5 |   | (0.9 | ) |
| Water Revenues                            |       | 0.4                                                          |       | 0.4 |   | 2.1 |   | 1.8 |   | 1.8 |   | 0.1 |   |
| Total Electric Segment Operating Revenues |       | $                                                            | 114.0      |   | $ | 106.8 |   | 6.8 |   | $ | 442.2 |   | $ | 446.3 |   | (0.9 | ) |

 

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**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, late paymentfees, renewable energy credit sales, rent, etc.*

 

***Quarter Ended March 31, 2010 Compared toQuarter Ended March 31, 2009***

 

**Operating Revenues and Kilowatt-Hour Sales**

 

KWh sales for our on-system customers increased during the firstquarter of 2010 as compared to the first quarter of 2009 primarily due tocolder weather in 2010. Revenues for our on-system customers increasedapproximately $5.0 million, or 5.0%. Weather and other related factorsincreased revenues an estimated $6.6 million. Total heating degree days (thesum of the number of degrees that the daily average temperature for each dayduring that period was below 65*°* F) for the first quarter of2010 were 19.3% more than the same period last year and 11.6% more than the30-year average. Continued sales growth contributed an estimated $0.3 million.Our electriccustomer growthfor the twelve months ended March 31, 2010 was 0.4%. Rate changes, mainlyresulting from fuel adjustment clauses, decreased revenues an estimated $1.9million.

 

During the first quarter of 2010, the increase in residential andcommercial kWh sales and revenues was primarily due to the colder weather inthe first quarter of 2010 and increased customer growth.

 

Industrial kWh sales and revenues decreased mainly due to a continuedslowdown created by economic uncertainty.

 

On-system wholesale kWh sales increased 5.1% and revenues increased5.1% during the first quarter of 2010 as compared to the same period in 2009reflecting the colder weather in the first quarter of 2010.

 

**Off-System Electric Transactions**

 

In addition to sales to our own customers, we also sell power to otherutilities as available, including through the Southwest Power Pool (SPP) energyimbalance services (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. As a result, nearly all of the off-systemsales margin flows back to the customer and has little effect on net income.

 

Revenues and related expenses were more during the first quarter of2010 as compared to the first quarter of 2009 primarily due to increased marketdemand resulting from colder weather inthe first quarter of 2010 as compared to thefirst quarter of 2009. Total purchased power related expenses are included inour discussion of purchased power costs below.

 

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**Miscellaneous Revenues**

 

Our miscellaneous revenues were $1.8 million during the first quarterof 2010 and the first quarter of 2009. These revenues are comprised mainly oftransmission revenues, late payment fees and renewable energy credit sales.

 

**Operating Revenue Deductions**

 

During the first quarter of 2010, total electric segment operatingexpenses increased approximately $10.5 million (11.5%) compared with the sameperiod last year.

 

Totalfuel and purchased power expenses increased approximately $3.9 million (8.3%)during the first quarter of 2010. The table below is a reconciliation of ouractual fuel and purchased power expenditures (netted with the regulatoryadjustments) to the fuel and purchased power expense shown on our statement ofincome for the first quarter of 2010 and 2009.

 
| **(in  millions)**                                           | ** ** | **2010** | ** ** | **2009** | ** ** |
|--------------------------------------------------------------|------------|----------|------------|----------|------------|
| Actual fuel and purchased power expenditures                 |       | $        | 53.1       |     | $          | 49.7 |   |
| Kansas regulatory adjustments*                               |       | (0.4     | )          | 0.3      |       |
| Missouri fuel adjustment deferral*                           |       | (1.8     | )          | (3.1     | )          |
| Missouri fuel adjustment recovery**                          |       | (0.5     | )          | —   |       |
| Unrealized (gain)/loss on derivatives                        |       | 0.3      |       | (0.1     | )          |
| Total fuel and purchased power expense per income  statement |       | $        | 50.7       |     | $          | 46.8 |   |

 

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

**Currently beingrefunded to customers from prior accumulation periods.

 

Theoverall fuel and purchased power increase reflects increased generation by bothour gas fired and coal fired units and a decrease in purchased power in thefirst quarter of 2010 as compared to 2009. The increase in fuel costs includestheeffect ofincreased market demand resulting from colder weather in the first quarter of2010 and increased off-system sales**.**

 

Summarizedin the table below are our estimated cost and volume changes in the componentsof fuel and purchased power expenses for the first quarter of 2010 as comparedto the first quarter of 2009. This table incorporates all the changes mentionedabove. As shown below, the largest impact on fuel and purchased power costs wasan increase in generation by our gas-fired units.

 
| ** **                           | ** ** | **Three Months Ended**           | ** ** |
|--------------------------------------|------------|----------------------------------|------------|
| **(in  millions)**                   | ** ** | **March 31, 2010 vs. 2009** | ** ** |
| Natural gas generation volume        |       | $                                | 6.0        |   |
| Coal generation volume               |       | 2.0                              |       |
| Purchased power spot purchase volume |       | (2.4                             | )          |
| Purchased power (cost)               |       | 0.5                              |       |
| Natural gas (cost)                   |       | (2.5                             | )          |
| Coal (cost)                          |       | (0.1                             | )          |
| Other (including fuel adjustments)   |       | 0.4                              |       |
| TOTAL                                |       | $                                | 3.9        |   |

 

Regulatedoperating expenses increased approximately $1.6 million (10.8%) during thefirst quarter of 2010 as compared to the same period in 2009 primarily due toincreases of $0.3 million in general labor costs, $0.3 million in customeraccounts expenses (mainly increased banking fees),$0.3 million in employee health care expense,$0.2 million in distribution expense, $0.2 million in injuries and damages,$0.1 million in general office expense, $0.1 million in property insurance,$0.1 million in employee pension expense, $0.1 million in other power operationexpense and $0.1 million

 

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inresearch and development expense. We were able to defer $0.3 million in othersteam power expense related to Iatan 1 operating costs in accordance with ouragreement with the MPSC that allows deferral of certain costs until theenvironmental upgrades to Iatan 1 are included in our rate base.

 

Maintenance and repairs expense increased approximately $0.1 million(0.9%) in the first quarter of 2010 as compared to the first quarter of 2009mainly due to increases of $0.4 million in maintenance and repairs expense atthe Riverton plant due to the 5-year maintenance outage which began on March 20,2010, $0.4 million in transmission and distribution maintenance, a $0.1 millionin maintenance and repairs expense at the Asbury plant and a $0.1 million inmaintenance and repairs expense at the Iatan plant. These increases were almostentirely offset by a $0.9 million decrease in maintenance and repairs expenseat the State Line Combined Cycle (SLCC) plant as compared to the first quarterof 2009 when there was a maintenance outage at the plant.

 

Depreciation and amortization expense increased approximately $0.5million (4.0%) during the quarter primarily reflecting our additions to plantin service. We deferred $0.3 million of depreciation expense due toconstruction accounting. Other taxes increased approximately $0.5 million duringthe first quarter of 2010 due to increased property tax reflecting ouradditions to plant in service and increased municipal franchise taxes.

 

***Twelve Months Ended March 31, 2010 Compared toTwelve Months Ended March 31, 2009***

 

**Operating Revenues and Kilowatt-Hour Sales**

 

For the twelve months ended March 31, 2010, kWh sales to ouron-system customers decreased 1.1% with the associated revenues increasingapproximately $5.6 million (1.4%). Rate changes, primarily the August 2008Missouri rate increase (discussed below), contributed an estimated $11.4million to revenues while continued sales growth contributed an estimated $1.2million. Weather and other related factors decreased revenues an estimated $7.0million. The increase in residential kWh sales and revenues during the twelvemonths ended March 31, 2010 was primarily due to colder weather in thefirst quarter of 2010 while the increase in residential revenues was also dueto the 2008 Missouri rate increase. Industrial and commercial kWh salesdecreased during the twelve months ended March 31, 2010, mainly due togeneral economic conditions. The associated revenues increased slightly forcommercial sales and the industrial revenues decreased less than the kWh salesdecreased reflecting the 2008 Missouri rate increase**.**On-system wholesale kWhsales decreased during the twelve months ended March 31, 2010 reflectingthe general economic conditions.

 

**Off-System Electric Transactions**

 

Off-system revenues decreased $9.6 million during the twelve monthsended March 31, 2010 as compared to the same period in 2009 primarily dueto decreased market demand and lower gas prices that made it more economicalfor utilities to generate their own power rather than purchase it in 2009**.**Total purchased powerrelated expenses are included in our discussion of purchased power costs below.

 

**Miscellaneous Revenues**

 

Our miscellaneous revenues for the twelve months ended March 31,2010 were $6.8 million as compared to $7.0 million in the same period of 2009.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, 2010, total electricsegment operating expenses decreased approximately $0.2 million (0.1%) comparedto the prior period.

 

Totalfuel and purchased power costs decreased approximately $8.0 million (4.1%)during the twelve months ended March 31, 2010. The table below is areconciliation of our actual fuel and

 

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purchasedpower expenditures (netted with the regulatory adjustments) to the fuel andpurchased power expense shown on our statement of income for the twelve monthsended March 31, 2010.

 
| **(in  millions)**                                           | ** ** | **2010** | ** ** | **2009** | ** ** |
|--------------------------------------------------------------|------------|----------|------------|----------|------------|
| Actual fuel and purchased power expenditures                 |       | $        | 185.6      |     | $          | 196.3 |   |
| Kansas regulatory adjustments*                               |       | (0.2     | )          | 0.2      |       |
| Missouri fuel adjustment deferral*                           |       | (0.7     | )          | (2.9     | )          |
| Missouri fuel adjustment recovery**                          |       | 1.2      |       | —   |       |
| Unrealized (gain)/loss on derivatives                        |       | —   |       | 0.3      |       |
| Total fuel and purchased power expense per income  statement |       | $        | 185.9      |     | $          | 193.9 |   |

 

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

**Currently beingrecovered from customers from prior accumulation periods.

 

Theoverall fuel and purchased power decrease includes theeffect of decreased marketdemand resulting from mild weather in the second, third and fourth quarters of2009. The decrease in fuel costs also includes the effect of decreasedoff-system sales.

 

Summarizedin the table below are our estimated cost and volume changes in the componentsof fuel and purchased power expenses for the twelve months ended March 31,2010 as compared to the twelve months ended March 31, 2009. This tableincorporates all the changes mentioned above. As shown below, the largestimpact on fuel and purchased power costs was a decrease in generation by our gas-firedunits.

 
| ** **                           | ** ** | **Twelve Months Ended**         | ** ** |
|--------------------------------------|------------|---------------------------------|------------|
| **(in  millions)**                   | ** ** | **March 31, 2010 vs 2009** | ** ** |
| Natural gas generation volume        |       | $                               | (12.4      | ) |
| Coal generation volume               |       | 1.2                             |       |
| Purchased power spot purchase volume |       | 0.2                             |       |
| Natural gas (cost)                   |       | 3.3                             |       |
| Coal (cost)                          |       | 2.4                             |       |
| Purchased power (cost)               |       | (5.7                            | )          |
| Other (including fuel adjustments)   |       | 3.0                             |       |
| TOTAL                                |       | $                               | (8.0       | ) |

 

Regulatedoperating expenses increased approximately $3.3 million (5.4%) during thetwelve months ended March 31, 2010 as compared to the same period in 2009,primarily due to increases of $1.2 million in general labor costs, $1.1 millionin professional services, $1.0 million in customer accounts expense (mainlyincreased banking fees), $0.6 million in other steam power expense at the Iatan1 plant, $0.5 million in transmission and distribution expense, $0.4 million inother steam power expense at the Asbury plant, $0.2 million in propertyinsurance, $0.2 million in employee welfare costs, $0.1 million in other poweroperation expense and $0.1 million in research and development expense. Theseincreases were partially offset by decreases of $0.7 million in injuries anddamages, $0.3 million in employee health care expense, $0.1 million in employeepension expense and $0.1 million in regulatory commission expense. We were ableto defer an additional $0.9 million in other steam power expense related toIatan 1 operating costs in accordance with our agreement with the MPSC thatallows deferral of certain costs until the environmental upgrades to Iatan 1are included in our rate base.

 

Maintenanceand repairs expense increased approximately $2.4 million (8.1%) during thetwelve months ended March 31, 2010 as compared to the twelve months ended March 31,2009 primarily due to increases of approximately $2.3 million in distributionmaintenance (including $1.5 million of ice storm-related amortization), $1.2million in maintenance and repairs expense at theAsbury plant, $0.4 million in transmissionmaintenance, $0.1 million in maintenance and repairs expense at the Ozark Beachplant and $0.1 million in repairs expense to the Riverton gas units. Theseincreases were partially offset by decreases of $1.1 million in maintenance andrepairs expense to the SLCC which experienced a maintenance outage in the firstquarter of 2009 and $0.6

 

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millionin maintenance and repairs expense at the Iatan 1 plant, which experienced anoutage in the fourth quarter of 2008.

 

Depreciation and amortization expense decreased approximately $0.8million (1.6%) during the twelve months ended March 31, 2010, primarilydue to reduced regulatory amortization resulting from the 2008 Missouri ratecase that went into effect on August 23, 2008 offset by increases to plantin service which increased depreciation expense. Other taxes increasedapproximately $1.0 million during the twelve months ended March 31, 2010due to increased property tax reflecting our additions to plant in service andincreased municipal franchise taxes.

 

***Gas Segment***

 

**Gas Operating Revenues and Sales**

 

The following tables detailour natural gas sales and revenues for the periods ended March 31:

 

**Total Gas Delivered to Customers**

 
| ** **                | ** ** | **Three Months Ended** | ** ** | **Twelve Months Ended** | ** ** |
|---------------------------|------------|------------------------|------------|-------------------------|------------|
| **(bcf  sales)**          | ** ** | **2010**               | ** ** | **2009**                | ** ** | **% change** | ** ** | **2010** | ** ** | **2009** | ** ** | **% change** | ** ** |
| Residential               |       | 1.51                   |       | 1.31                    |       | 15.4 | % | 2.89 |   | 2.73 |   | 5.8 | % |
| Commercial                |       | 0.65                   |       | 0.57                    |       | 15.1 |   | 1.36 |   | 1.29 |   | 5.4 |   |
| Industrial*               |       | 0.05                   |       | 0.15                    |       | (71.5 | ) | 0.11 |   | 0.66 |   | (83.5 | ) |
| Other**                   |       | 0.02                   |       | 0.02                    |       | 36.8 |   | 0.04 |   | 0.03 |   | 14.4 |   |
| Total retail sales        |       | 2.23                   |       | 2.05                    |       | 9.0 |   | 4.40 |   | 4.71 |   | (6.7 | ) |
| Transportation sales*     |       | 1.61                   |       | 1.16                    |       | 38.3 |   | 4.77 |   | 3.86 |   | 23.8 |   |
| Total gas operating sales |       | 3.84                   |       | 3.21                    |       | 19.6 |   | 9.17 |   | 8.57 |   | 7.0 |   |

 

**Operating Revenues and Cost of Gas Sold**

 
| ** **                                       | ** ** | **Three Months Ended** | ** ** | **Twelve Months Ended** | ** ** |
|--------------------------------------------------|------------|------------------------|------------|-------------------------|------------|
| **($ in  millions)**                        | ** ** | **2010**               | ** ** | **2009**                | ** ** | **% change** | ** ** | **2010** | ** ** | **2009** | ** ** | **% change** | ** ** |
| Residential                                      |       | $                      | 16.3       |                    | $          | 18.1 |   | (10.1 | )% | $ | 34.3 |   | $ | 39.6 |   | (13.4 | )% |
| Commercial                                       |       | 6.6                    |       | 7.4                     |       | (11.5 | ) | 14.7 |   | 17.4 |   | (15.3 | ) |
| Industrial*                                      |       | 0.3                    |       | 1.4                     |       | (76.2 | ) | 1.0 |   | 6.1 |   | (83.5 | ) |
| Other**                                          |       | 0.2                    |       | 0.2                     |       | (6.4 | ) | 0.4 |   | 0.4 |   | (8.6 | ) |
| Total retail revenues                            |       | $                      | 23.4       |                    | $          | 27.1 |   | (13.8 | ) | $ | 50.4 |   | $ | 63.5 |   | (20.6 | ) |
| Other revenues                                   |       | 0.1                    |       | 0.1                     |       | (27.8 | ) | 0.2 |   | 0.2 |   | (15.9 | ) |
| Transportation revenues*                         |       | 1.1                    |       | 0.9                     |       | 26.5 |   | 3.2 |   | 2.5 |   | 24.3 |   |
| Total gas operating revenues                     |       | $                      | 24.6       |                    | $          | 28.1 |   | (12.6 | ) | $ | 53.8 |   | $ | 66.2 |   | (18.8 | ) |
| Cost of gas sold                                 |       | 15.1                   |       | 19.3                    |       | (21.7 | ) | 31.4 |   | 44.2 |   | (29.0 | ) |
| Gas operating revenues over cost of gas in rates |       | $                      | 9.5        |                    | $          | 8.8 |   | 7.7 |   | $ | 22.4 |   | $ | 22.0 |   | 1.7 |   |

 

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**Percentagechange reflects the transfer of a customer from transportation to industrialsales in April 2008 and back to transportation in April 2009 and acustomer switching from industrial sales to transportation in October 2009after an eight-month suspension.*

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

 

***Quarter Ended March 31, 2010 Compared toQuarter Ended March 31, 2009***

 

**Operating Revenues and bcf Sales**

 

Gas retail sales increased9.0% during the first quarter of 2010 as compared to 2009 primarily due tocolder weather in the first quarter of 2010. The winter months are normallyhigh sales months for the natural gas business, whose heating season runs from November toMarch of each year. Residential sales increased 15.4% and commercial salesincreased 15.1% during the firstquarter of 2010 as compared to the firstquarter of 2009. Heating degree days were 15.4% more than the first quarter of2010 as compared to the first quarter of 2009 and 7.0% more than the 30-yearaverage. Industrial sales decreased 71.5% during the first quarter of 2010 ascompared to the same period in 2009 due to the transfers discussed above.

 

During the first quarter of2010, gas segment revenues were approximately $24.6 million as compared to$28.1 million in the first quarter of 2009, a decrease of 12.6%. During thefirst quarter of

 

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2010, our PGA revenue (which represents the cost of gas recoveredfrom our customers) was approximately $15.1 million as compared to $19.3million in the first quarter of 2009, a decrease of approximately $4.2 million.This decrease was largely driven by the decreases in the PGAs that went intoeffect May 15, 2009 and November 13, 2009.

 

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 balanceis recovered from or credited to customers. As of March 31, 2010, we hadunrecovered purchased gas costs of $0.3 million recorded as a regulatory assetand over recovered purchased gas costs of $4.0 million recorded as a regulatoryliability.

 

**OperatingRevenue Deductions**

 

Totalother operating expenses were $2.7 million during the first quarter of 2010 ascompared to $2.9 million in the first quarter of 2009, a decrease of $0.2million. This decrease was mainly due to a $0.2 million decrease inuncollectible accounts. Our gas segment had net income of $2.3 million for thefirst quarter of 2010 as compared to $1.8 million for the first quarter of2009.

 

***Twelve Months Ended March 31, 2010 Compared toTwelve Months Ended March 31, 2009***

 

**Operating Revenues and bcf Sales**

 

Gas retail sales decreased6.7% during the twelve months ended March 31, 2010 mainly due to the switching of customers between industrialsales and transportation, the suspension of operations of a large volumesales customer (see footnote above),and the effect of our gas segment customer contraction of 0.8% for the twelve months ended March 31,2010. We believe thiscontraction was due to depressed economic conditions. We estimate that the rateof gas customer contraction will level out during the next three years andbegin modest growth after 2012. Residential and commercial salesincreased during the twelve months ended March 31, 2010 primarily due tocolder weather in the first quarter of 2010.

 

During the twelve monthsended March 31, 2010, gas segment revenues were approximately $53.8million as compared to $66.2 million in the twelve months ended March 31,2009, a decrease of $12.5 million (18.8%). This decrease was largely driven bya decrease in the PGAs that went into effect May 15, 2009 and November 13,2009. During the twelve months ended March 31, 2010, our PGA revenue wasapproximately $31.4 million as compared to $44.2 million during the twelvemonths ended March 31, 2009, a decrease of approximately $12.8 million.

 

**OperatingRevenue Deductions**

 

Totalother operating expenses were $10.1 million for the twelve months ended March 31,2010 as compared to $10.4 million for the twelve months ended March 31,2009. This decrease was mainly due to a $0.5 million decrease in customeraccounts expense (mainly uncollectible accounts) partially offset by a $0.2million increase in distribution operation expense. Our gas segment had netincome of $1.4 million for the twelve months ended March 31, 2010 ascompared to $1.0 million for the twelve months ended March 31, 2009.

 

***Consolidated Company***

 

**Income Taxes**

 

Ourconsolidated provision for income taxes increased approximately $4.4 millionduring the first quarter of 2010 as compared to the same period in 2009primarily due to the non-cash charges in the first quarter of 2010 discussedbelow. Our consolidated provision for income taxes increased

 

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approximately $2.4 millionduring the twelve months ended March 31, 2010 as compared to the twelvemonths ended March 31, 2009.

 

Thefollowing table shows our consolidated effective federal and state income taxrates for the applicable periods ended September 30, 2009:

 
| ** **                                                 | ** ** | **Three Months Ended** | ** ** | **Twelve Months Ended** | ** ** |
|------------------------------------------------------------|------------|------------------------|------------|-------------------------|------------|
| ** **                                                 | ** ** | **2010**               | ** ** | **2009**                | ** ** | **2010** | ** ** | **2009** | ** ** |
| Consolidated  effective federal and state income tax rates |       | 53.6                   | %          | 33.9                    | %          | 38.3 | % | 33.1 | % |

 

The effective tax rates for the first quarter of 2010 and the twelvemonths ended March 31, 2010 are higher than comparable prior year periodsprimarily due to the new health care legislation. On March 23, 2010, thePatient Protection and Affordable Care Act became law. This legislationincludes a provision that reduces the deductibility, for income tax purposes,of retiree healthcare costs to the extent an employer receives federal subsidies.Companies receive the subsidy when they provide retiree prescription benefitsat least equivalent to Medicare Part D coverage in their postretirementhealthcare plan. Although the elimination of this tax benefit does not takeeffect until 2013, this change requires us to recognize the full accountingimpact in our financial statements in the period in which the legislation isenacted. As a result, in the first quarter of 2010, we recorded a one-timenon-cash charge of approximately $2.1 million to income taxes to reflect theimpact of this change. Our 2010 effective tax rate is also expected to increasedue to the additional tax expense associated with the current year retireehealth care accruals.

 

As part of an agreementreached in our current Missouri electric rate case, we have also agreed tocommence an eighteen year amortization of a deferred asset related to the taxbenefits of cost of removal. These tax benefits were flowed through tocustomers from 1981-2008 and totaled approximately $11.1 million. We recorded aregulatory asset expecting to recover these benefits from customers in futureperiods. We estimated the portion of the amortization period where raterecovery would no longer be probable for this item and wrote off approximately$1.2 million. Amortization of the remaining regulatory tax asset will begin in2012, which is also when we expect to be able to request rate recovery of theasset. As a result of the two non-cash charges, our effective income tax ratefor the 2010 first quarter was approximately 54% compared to 34% in the 2009period. Excluding these non-cash charges, the effective tax rate in the 2010first quarter would have been 36%.

 

We do not expect anysignificant changes to our unrecognized tax benefits over the next twelve months.The reserve balance related to unrecognized tax benefits as of December 31,2009 was $906,000 and has not materially changed at March 31, 2010.

 

**Nonoperating Items**

 

The following table shows the total allowance forfunds used during construction (AFUDC) for the applicable periods ended March 31. AFUDC increased during both the firstquarter of 2010 and the twelve months ended March 31, 2010 as compared tothe same periods in 2009 due to higher levels of construction in each period.

 
| ** **                                             | ** ** | **Three Months Ended** | ** ** | **Twelve Months Ended** | ** ** |
|--------------------------------------------------------|------------|------------------------|------------|-------------------------|------------|
| **($ in  millions)**                              | ** ** | **2010**               | ** ** | **2009**                | ** ** | **2010** | ** ** | **2009** | ** ** |
| Allowance  for equity funds used during construction   |       | $                      | 1.8        |                    | $          | 1.4 |   | $ | 6.6 |   | $ | 6.2 |   |
| Allowance  for borrowed funds used during construction |       | 2.4                    |       | 2.2                     |       | 8.1 |   | 7.4 |   |
| Total  AFUDC                                           |       | $                      | 4.2        |                    | $          | 3.6 |   | $ | 14.7 |   | $ | 13.6 |   |

 

Totalinterest charges on long-term and short-term debt for the periods ended March 31,2010 are shown below. The increases in long-term debt interest for both periodsreflect the interest on the $75 million principal amount of first mortgagebonds we issued March 27, 2009. The increases in long-term debt interestfor the twelve months ended March 31, 2010 also reflect the $90 millionprincipal amount of first mortgage bonds we issued May 16, 2008. Thedecreases in short-term debt interest primarily reflect lower levels ofborrowing.

 

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| ** **                          | ** ** | **Interest Charges**     | ** ** |
|-------------------------------------|------------|--------------------------|------------|
| ** **                          | ** ** | **($ in millions)** | ** ** |
| ** **                          | ** ** | **3 Months**             | ** ** | **3 Months** | ** ** | ** ** | ** ** | **12 Months** | ** ** | **12 Months** | ** ** | ** ** | ** ** |
| ** **                          | ** ** | **Ended**                | ** ** | **Ended** | ** ** | **%** | ** ** | **Ended** | ** ** | **Ended** | ** ** | **%** | ** ** |
| ** **                          | ** ** | **2010**                 | ** ** | **2009** | ** ** | **Change*** | ** ** | **2010** | ** ** | **2009** | ** ** | **Change*** | ** ** |
| Long-term debt interest             |       | $                        | 10.5       |   | $ | 9.6 |   | 8.8 | % | $ | 42.9 |   | $ | 37.6 |   | 14.2 | % |
| Short-term debt interest            |       | 0.2                      |       | 0.6 |   | (57.8 | ) | 0.8 |   | 1.9 |   | (58.5 | ) |
| Trust preferred securities interest |       | 1.1                      |       | 1.1 |   | 0.0 |   | 4.3 |   | 4.3 |   | 0.0 |   |
| Iatan 1 carrying charges*           |       | (0.6                     | )          | — |   | — |   | (1.9 | ) | — |   | — |   |
| Other interest                      |       | 0.2                      |       | 0.1 |   | 51.0 |   | 0.7 |   | 1.1 |   | (31.5 | ) |
| Total interest charges              |       | $                        | 11.4       |   | $ | 11.4 |   | 0.0 |   | $ | 46.8 |   | $ | 44.9 |   | 4.3 |   |

 

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**Beginning in the second quarter of 2009, we are able to defer Iatan 1carrying charges in accordance with our agreement with the MPSC that allowsdeferral of certain costs until the environmental upgrades to Iatan 1 areincluded in our rate base.*

 

**RATE MATTERS**

 

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

 

Ourrates for retail electric and natural gas services (other than speciallynegotiated retail rates for industrial or large commercial customers, which aresubject to regulatory review and approval) are determined on a “cost of service”basis. Rates are designed to provide, after recovery of allowable operatingexpenses, an opportunity for us to earn a reasonable return on “rate base.” “Ratebase” is generally determined by reference to the original cost (net ofaccumulated depreciation and regulatory amortization) of utility plant inservice, subject to various adjustments for deferred taxes and other items.Over time, rate base is increased by additions to utility plant in service andreduced by depreciation, regulatory amortization and retirement of utilityplant and write-off’s as ordered by the utility commissions. In general, arequest of new rates is made on the basis of a “rate base” as of a date priorto the date of the request and allowable operating expenses for a 12-month testperiod ended prior to the date of the request. Although the current rate makingprocess provides recovery of some future changes in rate base and operatingcosts, it does not reflect all changes in costs for the period in which newretail rates will be in place. This results in a lag between the time we incurcosts and the time when we can start recovering the costs through rates. SeeNote 3 of “Notes to Consolidated Financial Statements” for the amounts recordedfor regulatory amortization.

 

Thefollowing table sets forth information regarding rate increases since January 1,2008:

 
| **Jurisdiction**         | ** ** | **Date  Requested**  | ** ** | **Annual  Increase  Granted** | ** ** | **Percent  Increase  Granted** | ** ** | **ROE** | ** ** | **Date Effective** | ** **           |
|--------------------------|------------|----------------------|------------|-------------------------------|------------|--------------------------------|------------|---------|------------|--------------------|----------------------|
| Missouri — Gas      |       | June 5, 2009    |       | $                             | 2,600,000  |                           | 4.37       | %       | N/A        |               | April 1, 2010   |   |
| Missouri — Electric |       | October 1, 2007 |       | $                             | 22,040,395 |                           | 6.70       | %       | 10.8       | %                  | August 23, 2008 |   |

 

***Electric Segment***

 

*Missouri*

 

*2009 Rate Case*

 

OnOctober 29, 2009, we filed a request with the MPSC for an annual increasein base rates for our Missouri electric customers in the amount of $68.2million, or 19.6%. This request was primarily designed to allow us to recover capitalexpenditures associated with environmental upgrades at Iatan 1 and ourinvestment in new generating units at Iatan 2 and the Plum Point GeneratingStation. On April 30, 2010, the parties in this rate case filed a pleadingwith the MPSC stating that we have reached an agreement in principle as to allissues in the case. We expect the agreement to be filed sometime in May 2010.

 

Asa result of the delay in the Iatan 2 project, however, we have agreed to notseek a permanent increase in the current rate case for any costs associatedwith the Iatan 2 unit with the exception of that portion of the Iatan 2 commonplant needed to operate Iatan 1. We currently expect Iatan 2 to be placed intoservice in the fall of 2010 and anticipate filing a rate case at the conclusion

 

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ofthis case to recover the Iatan 2 costs. See Note 7 of “Notes to ConsolidatedFinancial Statements.” We have also agreed to the use of constructionaccounting for our Plum Point project such as we use for our Iatan 2 project.Construction accounting allows us to defer certain charges as regulatoryassets, including depreciation and carrying costs, related to operation of thefacilities until the facilities are ultimately included in our rate base. Wehave also agreed to commence an eighteen year amortization of a deferred assetrelated to the tax benefits of cost of removal. These tax benefits were flowedthrough to customers from 1981 to 2008 and totaled approximately $11.1 million.We had previously recorded a regulatory asset expecting to recover thesebenefits from customers in future periods. We estimated the portion of theamortization period where rate recovery would no longer be probable for thisitem and wrote off approximately $1.2 million. Amortization of the remainingregulatory tax asset will begin in 2012, which is also when we expect to beable to request rate recovery of the asset. See Note 12 of “Notes toConsolidated Financial Statements”.

 

*2007 Rate Case*

 

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

 

The order contains two components. The firstcomponent provides an addition to base rates of approximately $27.7 million. Thisincrease in base rates was partially offset by a $5.7 million reduction toregulatory amortization, which is the second component to support certaincredit metrics of the overall change in revenue authorized by the MPSC.Regulatory amortization provides us additional cash through rates during thecurrent construction cycle. This construction, which is part of our long-rangeplan to ensure reliability, includes the facilities at the Riverton Power Plantand Iatan 2 Power Plant, as well as environmental improvements at the AsburyPower Plant and at Iatan 1. The regulatory amortization is now approximately$4.5 million annually and is recorded as depreciation expense.

 

The MPSC also authorized a fuel adjustmentclause for our Missouri customers effective September 1, 2008. The MPSCestablished a base cost for the recovery of fuel and purchased power expensesused to supply energy. The clause permits the distribution to customers of 95%of the changes in fuel and purchased power costs above or below the base cost.Off-system sales margins are also part of the recovery of fuel and purchasedpower costs. As a result, the off-system sales margin flows back to thecustomer. Rates related to the recovery of fuel and purchased power costs willbe modified twice a year subject to the review and approval by the MPSC. Inaccordance with accounting guidance for regulated activities, 95% of thedifference between the actual cost of fuel and purchased power and the basecost of fuel and purchased power recovered from our customers is recorded as anadjustment to fuel and purchased power expense with a corresponding regulatoryasset or a regulatory liability. If the actual fuel and purchased power costsare higher or lower than the base fuel and purchased power costs billed tocustomers, 95% of these amounts will be recovered or refunded to our customerswhen the fuel adjustment clause is modified. On April 1, 2009, we filedproposed rate schedules with the MPSC requesting an increase of $1.9 million inrevenues for the under recovered fuel costs recognized for the six month periodended February 28, 2009. This increase in revenue was approved by the MPSCon May 21, 2009, became effective June 1, 2009 and is billed throughour fuel adjustment clause. On October 1, 2009, we filed proposed rateschedules with the MPSC requesting a decrease of $0.8 million in revenues forthe over recovered fuel and purchased power costs recognized for the six monthperiod ended August 31, 2009.

 

The MPSC order in the rate case approved aStipulation and Agreement providing for the recovery of deferred expenses ofapproximately $14.2 million over a five year period for the 2007 ice storms. Inaddition, the MPSC order required the implementation of a two-way trackingmechanism for recovery of the costs relating to the new MPSC rules oninfrastructure inspection and vegetation management. The mechanism authorizedby the MPSC creates a regulatory liability in any year we spend less than thetarget amount, which has been set at $8.6 million for our Missourijurisdiction, and a regulatory asset if we spend more than the target amount.Any regulatory asset and liability amounts created using the tracking mechanismwill then be netted against each other and taken into

 

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account in our next rate case. The MPSC also approved Stipulations andAgreements providing for the continuation of the pension and other post-retirementemployee benefits tracking mechanism established in our 2006 and 2007 Missourirate orders.

 

The MPSC issued its Report andOrder 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 and intervenorsPraxair, Inc. and Explorer Pipeline Company filed Petitions forWrit of Review with the Cole County Circuit Court. These actions wereconsolidated into one proceeding, briefs were filed and the Cole County CircuitCourt heard oral arguments on September 29, 2009. The Cole County CircuitCourt issued a ruling on December 31, 2009, affirming the Commission’sReport and Order. OPC, Praxair and Explorer Pipeline have filed appeals withthe Missouri Court of Appeals.

 

*Kansas*

 

On November 4, 2009, we filed a request with the KCC for an annualincrease in base rates for our Kansas electric customers in the amount of $5.2million, or 24.6%. This request is primarily to allow us to recover capitalexpenditures associated with environmental upgrades at Iatan 1 completed in2009 and at our Asbury plant completed in 2008 and our investment in newgenerating units at Iatan 2, the Plum Point Generating Station and our Riverton12 unit that went on line in 2007. On May 4, 2010, we filed a stipulationwith the parties to the rate case, pending KCC approval. We anticipate newrates will go into effect in July 2010.

 

*Oklahoma*

 

OnMarch 25, 2010, we requested a capital cost recovery rider (CCRR) at theOCC. The rider is designed to recover the carrying costs on our capitalinvestment for generation, transmission and distribution assets that have beenadded to the system since our last Oklahoma general rate case (May 2003),as well as investments made on an ongoing basis. As requested, the operation ofthe CCRR would increase our operating revenue in Oklahoma in a series of threesteps to be followed with a general rate case in 2011. If the CCRR isauthorized by the OCC, it is expected to result in a maximum overall increasein Oklahoma revenues of approximately $3 million pre-tax, or approximately 33%.

 

*FERC*

 

OnMarch 12, 2010, we filed Generation Formula Rate (GFR) tariffs with theFERC which will be utilized for our wholesale customers. New rates based on theGFR tariffs are expected to be effective around August 1, 2010.

 

***Gas Segment***

 

OnJune 5, 2009, we filed a request with the MPSC for an annual increase inbase rates for our Missouri gas customers in the amount of $2.9 million, or4.9%. In this filing, we requested recovery of the ongoing cost of operating andmaintaining our 1,200-mile gas distribution system and a return on equity of11.3%. On February 24, 2010, the MPSC unanimously approved an agreementamong the Office of the Public Counsel (OPC), the MPSC staff and Empire for anincrease of $2.6 million. Pursuant to the Agreement, new rates went into effecton April 1, 2010.

 

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**COMPETITION**

 

***Electric Segment***

 

*SPP-RTO*

 

EnergyImbalance Services:  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.

 

Day-AheadMarket:  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 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 2013 orearly 2014. 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.

 

SPP Regional Transmission Development:  On August 15, 2008, the SPP filed withthe FERC proposed revisions to its open access transmission pro forma tariff(OATT) to establish a process for including a “balanced portfolio” of economictransmission upgrades in the annual SPP Transmission Expansion Plan. The costof such upgrades will be recovered through a regional rate allocated to SPPmembers based on their load ratio share within SPP’s market area of thebalanced portfolio’s cost. On October 16, 2008, the FERC accepted thebalanced portfolio approach, which sets forth the selection process of a groupof projects and regional cost allocation rules based on projected benefitsand allocated costs over a ten year period. The plan will be balanced if theportfolio is cost beneficial for each zone, including ours, within the SPP. Abalanced portfolio could include projects below the 345 kv level (which is thebright line voltage level for projects to be included in the portfolio) toincrease benefits to a particular zone to achieve balance of benefits and costsover the ten year study period. On April 28, 2009, the SPP RSC and the SPPBOD approved the first set of balanced portfolio extra high voltagetransmission projects to be constructed within the SPP region. The transmissionexpansion projects, totaling over $700 million, include projects in Missouri,Kansas, Arkansas, Oklahoma, Nebraska and Texas. We anticipate this set oftransmission expansion projects will provide long term benefits to ourcustomers yet expect our share of the net allocated costs to be immaterial.Also on April 28, 2009, the SPP RSC and BOD approved a new report thatrecommends restructuring of the SPP’s regional planning processes, which wouldestablish an integrated planning process for reliability, transmission serviceand economic transmission projects, based on a new set of planning principlesthat focus on the construction of a more robust transmission system largeenough in both scale and geography to provide flexibility to meet SPP members’and customers’ future needs. We will actively participate in the development ofthese new processes as well as cost allocation and recovery issues withmembers, prospective customers and the state commission representatives to theSPP RSC. On October 27, 2009, the SPP BOD endorsed a new transmission costallocation method to replace the existing FERC accepted cost allocation methodfor new

 

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transmissionfacilities needed to continue to reliably and economically serve SPP customers,including ours, well into the future. The SPP BOD has approved the filing ofnew cost allocation tariff language that would require all transmissionprojects of 300 kV or larger to be funded by the region as a whole. Thisproposed cost allocation method, the “highway-byway” plan, would also requirethe region as a whole to pay 33% of the cost of transmission projects between100 kV and 300 kV, while individual constructing zones pay 67% of those projectsbuilt within their zone. For projects under 100kV, the constructing zones wouldpay 100% of the cost. The new cost allocation method will be filed by the SPPat the FERC in the second quarter of 2010. We continue to evaluate the cost andbenefit impacts and our position on the new cost allocation method to determinewhether a challenge of the SPP filing at the FERC will be necessary.

 

*FERC Market Power Order*

 

OnMarch 3, 2005, the FERC issued an order commencing an investigation todetermine if we had market power within our control area based on our failureto meet one of the FERC’s wholesale market share screens. We filed responses tothat order in May and June 2005 and in early January 2006. On August 15,2006, the FERC issued its order accepting Empire’s proposed mitigation tobecome effective May 16, 2005, subject to a further compliance filing asdirected in the order. Relying on a series of orders issued since March 17,2006 in other proceedings, the FERC rejected our tariff language and directedus to file revisions to our market-based tariff to provide that service underthe tariff applies only to sales outside our control area. The FERC directed usto make refunds, with interest, by September 15, 2006,  covering over 1,000 hourly energy sales sinceMay 16, 2005 to numerous counterparties external to our system forwholesale sales made at market prices above the cost based prices permittedunder the mitigation proposal accepted by the FERC. The refund obligationapplied to certain wholesale power sales made “inside” our service area atmarket based rates, even though consumption of the energy occurred outside ourservice area.

 

OnSeptember 14, 2006, we filed a Request for Rehearing of the FERC’s August 15,2006 order regarding the refund and market power mitigation we had proposed. Werequested a rehearing and a waiver of the refund requirement in its entirety.On April 25, 2008, the FERC issued an Order that rejected our Request ForRehearing, required a Compliance Filing of our market based rate tariff andordered refunds with interest. We made our Compliance Filing and issued refundstotaling $340,608, including interest, on May 27, 2008. We also filed aninformational refund report with the FERC on June 26, 2008.

 

Aspart of our market based pricing authority, we are required to conduct a marketpower analysis within our service territory and within the SPP RTO region everythree years. We filed our triennial market power analysis with the FERC on July 30,2009, concluding there were no material changes to our market position. As aresult, we do not anticipate any changes to our existing market based rateauthority. The FERC’s acceptance of our filing is pending.

 

*Other FERC Activity*

 

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

 

OnMay 21, 2009, the FERC issued an order clarifying that, going forward,small public utilities that have been granted waiver of Order No. 889(Open Access Same Time Information Systems (OASIS) requirement) and theStandards of Conduct for transmission operations, which includes us, arerequired to submit a notification filing if there has been a material change infacts that may affect

 

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thebasis on which a public utility’s waiver was premised. The Standards of Conductgenerally govern the communications between our day to day transmissionoperations personnel and our day to day wholesale marketing and salespersonnel. We submitted our filing on July 13, 2009 in which we believecontinuation of our waiver, issued in 1997 and reaffirmed in 2004, isappropriate and reasonable. Based on the May 21, 2009 order, it ispossible that the FERC will revoke our waiver which would impact communicationbetween our transmission and wholesale marketing and sales functions andoperations within our organization. As part of our filing, we sought a twelvemonth extension in order to comply with the Standard of Conduct requirements inthe event the FERC determined that revoking our waiver was appropriate. TheFERC’s decision on this and other Standard of Conduct waiver filings ispending.

 

***Gas Segment***

 

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

 

**LIQUIDITY AND CAPITALRESOURCES**

 

***Overview.             ***Our primary sources ofliquidity are cash provided by operating activities, short-term borrowingsunder our commercial paper program (which is supported by our creditfacilities) and borrowings from our unsecured revolving credit facility.**As needed, we raise funds from the debt and equity capitalmarkets, including through our existing shelf registration statement, to fundour liquidity and capital resource needs.

 

Our issuance of various securities, includingequity, long-term and short-term debt, is subject to customary approval orauthorization by state and federal regulatory bodies including state publicservice commissions and the SEC. We estimate that internally generated funds(funds provided by operating activities less dividends paid) will provide onlya portion of the funds required in 2010 for our budgeted capital expenditures(as discussed in “Capital Requirements and Investing Activities” below).Although our working capital was negative as of March 31, 2010, we believethe amounts available to us under our credit facilities and the issuance ofdebt and equity securities together with this cash provided by operatingactivities will allow us to meet our needs for working capital, pensioncontributions, our continuing construction expenditures, anticipated debtredemptions, interest payments on debt obligations, dividend payments and othercash needs through the next several years.

 

Wewill continue to evaluate our need to increase available liquidity based on ourview of working capital requirements, including the timing of our constructionprograms and other factors. The following table provides a summary of ouroperating, investing and financing activities for the quarters ended March 31:

 

**Summaryof Cash Flows**

 
| ** **                               | ** ** | **Quarter Ended March 31,** | ** ** |
|------------------------------------------|------------|----------------------------------|------------|
| **(in  millions)**                       | ** ** | **2010**                         | ** ** | **2009** | ** ** |
| Cash  provided by (used in):             |       |                             |       |   |   |
| Operating  activities                    |       | $                                | 36.8       |   | $ | 38.1 |   |
| Investing  activities                    |       | (34.8                            | )          | (41.5 | ) |
| Financing  activities                    |       | (1.7                             | )          | 8.7 |   |
| Net  change in cash and cash equivalents |       | $                                | 0.3        |   | $ | 5.3 |   |

 

**Cashflow from Operating Activities**

 

Weprepare our statement of cash flows using the indirect method. Under thismethod, we reconcile net income to cash flows from operating activities byadjusting net income for those items

 

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thatimpact net income but may not result in actual cash receipts or payments duringthe period. These reconciling items include depreciation and amortization,pension costs, deferred income taxes, equity AFUDC, changes in commodity riskmanagement assets and liabilities and changes in the consolidated balance sheetfor working capital from the beginning to the end of the period.

 

Period-over-periodchanges in our operating cash flows are attributable primarily to workingcapital changes resulting from the impact of weather, the timing of customercollections, payments for natural gas and coal purchases and the effects ofdeferred fuel recoveries. The increase in natural gas prices directly impactsthe cost of gas stored in inventory.

 

*FirstQuarter 2010 Compared to 2009**. *During the first quarter of 2010, our net cash flow provided fromoperating activities was $36.8 million, a decrease of $1.3 million or 3.4% from2009. This decrease was primarily a result of:

 

·                  Changes in net income - $(2.3) million.

·                  Draw down of the commodity risk managementmargin accounts through settlement of hedged positions in 2009 - $(5.2)million.

·                  Changes in seasonal levels of inventory,including the effect of building coal inventories at Plum Point and Iatan 2 - $(6.8)million.

·                  Changes in levels of accounts receivables - $(1.2)million.

·                  Changes in accrued liabilities - $8.5million.

·                  Changes in cash payments for income taxes -$2.7 million.

·                  Accrual over recovered fuel costs - $3.0million.

 

**CapitalRequirements and Investing Activities**

 

Ournet cash flows used in investing activities decreased $6.7 million during thefirst quarter of 2010 as compared to the first quarter of 2009.

 

Our capital expenditures incurred totaled approximately $30.9 millionduring the first quarter of 2010 compared to $41.0 million in the first quarterof 2009. The decrease was primarily the result of a decrease in distributionand transmission system additions and decreased generation additions followingthe completion of the Iatan I environmental upgrades.

 

A breakdown of the capital expenditures for the quarters ended March 31,2010 and 2009 is as follows:

 
| ** **                                                   | ** ** | **Capital Expenditures** | ** ** |
|--------------------------------------------------------------|------------|--------------------------|------------|
| **(in  millions)**                                           | ** ** | **2010**                 | ** ** | **2009** | ** ** |
| Distribution  and transmission system additions              |       | $                        | 7.4        |   | $ | 10.2 |   |
| New  Generation – Plum Point Energy Station             |       | 3.5                      |       | 5.0 |   |
| New  Generation – Iatan 2                               |       | 19.0                     |       | 16.2 |   |
| Storms                                                       |       | —                   |       | 0.3 |   |
| Additions  and replacements – electric plant            |       | 0.3                      |       | 8.8 |   |
| Gas  segment additions and replacements                      |       | 0.2                      |       | 0.4 |   |
| Transportation                                               |       | 0.2                      |       | 0.2 |   |
| Other  (including retirements and salvage - net) (1)         |       | (1.1                     | )          | (0.7 | ) |
| **Subtotal**                                                 |       | 29.5                     |       | 40.4 |   |
| Non-regulated  capital expenditures (primarily fiber optics) |       | 1.4                      |       | 0.6 |   |
| **Subtotal capital expenditures incurred**(2)                |       | 30.9                     |       | 41.0 |   |
| Adjusted  for capital expenditures payable****(3)            |       | 3.9                      |       | 0.9 |   |
| **Total cash outlay**                                        |       | $                        | 34.8       |   | $ | 41.9 |   |

 

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(1) ****Otherincludes equity AFUDC of $(1.8) million and $(1.4) million for 2010 and 2009,respectively.

(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. These capital expenditures include AFUDC,capital expenditures to retire assets and benefits from salvage.

(3) The amount of expenditures paid/(unpaid)at the end of the reporting period to adjust to actual cash outlay reflected inthe Investing Activities section of the Statement of Cash Flows.

 

Approximately70% of our cash requirements for capital expenditures during the first quarterof 2010 were satisfied internally from operations (funds provided by operatingactivities less dividends

 

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paid).The remaining amounts of such requirements were satisfied from short-termborrowings and proceeds from our sales of common stock and debt securitiesdiscussed below.

 

Weestimate that internally generated funds will provide approximately 57% of thefunds required for the remainder of our budgeted 2010 capital expenditures. Weintend to utilize a combination of short-term debt, the proceeds of sales oflong-term debt and/or common stock (including common stock sold under ourequity distribution agreement discussed below, as well as under our EmployeeStock Purchase Plan, our Dividend Reinvestment and Stock Purchase Plan, and our401(k) Plan and ESOP) to finance additional amounts needed beyond thoseprovided by operating activities for such capital expenditures. We willcontinue to utilize short-term debt as needed to support normal operations orother temporary requirements. For further information see Note 6 of “Notes toConsolidated Financial Statements (Unaudited).”

 

**FinancingActivities**

 

Ournet cash flows provided by financing activities decreased $10.4 million in thefirst quarter of 2010 as compared to 2009.

 

Duringthe first quarter of 2010, we issued and sold 1,678,341 shares of our commonstock pursuant to our equity distribution program, at an average price pershare of $18.27, resulting in proceeds to us of approximately $29.7 million(after payment of approximately $0.9 million in commissions to the salesagent). Since inception of the program, in the aggregate, we have issued andsold 5,479,863 shares pursuant to the program, resulting in net proceeds to usof approximately $96.9 million. In 2009 we issued $75 million in first mortgagebonds as discussed below. In 2010 we paid down $21.5 million in short-term debtversus $54.8 million in 2009. See Note 6 of “Notes to Consolidated FinancialStatements (Unaudited)” for additional information regarding our equitydistribution program.

 

OnMarch 27, 2009, we issued $75 million principal amount of 7% firstmortgage bonds due April 1, 2024. The net proceeds (after payment ofexpenses) of approximately $72.6million were used to repay short-term debt incurred, in part, to fundour current construction program.

 

Wehave a $400 million shelf registration statement with the SEC, which becameeffective on August 15, 2008, covering our common stock, unsecured debtsecurities, preference stock, first mortgage bonds and trust preferredsecurities. As of March 31, 2010, in addition to amounts remaining underthe equity distribution program described above, $205 million remains availablefor issuance under this shelf registration statement. Of the original $400million, $250 million was available for first mortgage bonds with $175 millionremaining available after the issuance of $75 million in first mortgage bondson March 27, 2009. We plan to use a portion of the proceeds from issuancesunder this shelf to fund a portion of the capital expenditures for our newgeneration projects and to refinance long-term debt.

 

OnJuly 15, 2005, we entered into a $150 million unsecured revolving creditfacility which was scheduled to terminate on July 15, 2010. On March 14,2006, we entered into the First Amended and Restated Unsecured Credit Agreementwhich amended and restated the $150 million unsecured revolving creditfacility. The principal amount of the credit facility was increased to $226million, with the additional $76 million allocated to support a letter ofcredit issued in connection with our participation in the Plum Point EnergyStation project. This extra $76 million of availability reduces over a fouryear period in line with the amount of construction expenditures we owe forPlum Point Unit 1 and was $7.5 million as of May 1, 2010. On January 26,2010, we entered into the Second Amended and Restated Unsecured CreditAgreement which amended and restated this facility again. This agreementextends the termination date of the revolving credit facility from July 15,2010 to January 26, 2013. In addition, the pricing and fees under thefacility were amended. Interest on borrowings under the facility accrues at arate equal to, at our option, (i) the highest of (A) the bank’s primecommercial rate, (B) the federal funds effective rate plus 0.5% or (C) onemonth LIBOR plus 1.0%, plus a margin or (ii) one month, two month or threemonth LIBOR, in each case, plus a margin. Each margin is based on our currentcredit ratings and the pricing schedule in the facility. As of the date hereof,and based on our current credit ratings, the LIBOR margin under the facilityincreased from 0.80% to 2.70%. A facility fee is payable quarterly on the fullamount of the commitments under the facility and a usage fee is payable on thefull amount of the commitments under the facility for any

 

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periodin which we have drawn less than 33% of the total revolving commitments underthe facility, in each case based on our current credit ratings. In addition,upon entering into the amended and restated facility, we paid an upfront fee tothe revolving credit banks of $900,000 in the aggregate. The aggregate amountof the revolving commitments remained unchanged at $150 million and there wereno other material changes to the terms of the facility. The facility is usedfor working capital, general corporate purposes and to back-up our use ofcommercial paper. This facility requires our total indebtedness (which does notinclude our trust preferred securities) to be less than 62.5% of our totalcapitalization at the end of each fiscal quarter and our EBITDA (defined as netincome plus interest, taxes, depreciation and amortization) to be at least twotimes our interest charges (which includes interest on the trust preferredsecurities) for the trailing four fiscal quarters at the end of each fiscalquarter. Failure to maintain these ratios will result in an event of defaultunder the credit facility and will prohibit us from borrowing funds thereunder.As of March 31, 2010, we are in compliance with these ratios. This creditfacility is also subject to cross-default if we default on in excess of $10million in the aggregate on our other indebtedness. This arrangement does notserve to legally restrict the use of our cash in the normal course ofoperations. There was $14.0 million of outstanding borrowings under thisagreement at March 31, 2010 and an additional $15.0 million was used toback up our outstanding commercial paper.

 

OnMarch 11, 2009, we entered into a $50 million unsecured credit agreement.This agreement provides for $50 million of revolving loans to be available tous for working capital, general corporate purposes and to back-up our use ofcommercial paper and terminates on July 15, 2010. This credit agreement isin addition to, and has substantially identical covenants and terms as (otherthan pricing) our Second Amended and Restated Unsecured Credit Agreement dated January 26,2010 discussed above. There were no borrowings under this agreement at March 31,2010.

 

Theprincipal amount of all series of first mortgage bonds outstanding at any onetime under the EDE Mortgage is limited by terms of the mortgage to $1 billion.Substantially all of the property, plant and equipment of The Empire DistrictElectric Company (but not its subsidiaries) is subject to the lien of the EDEMortgage.****Restrictions inthe EDE mortgage bond indenture could affect our liquidity. The EDE Mortgagecontains a requirement that for new first mortgage bonds to be issued, our netearnings (as defined in the EDE Mortgage) for any twelve consecutive monthswithin the fifteen months preceding issuance must be two times the annualinterest requirements (as defined in the EDE Mortgage) on all first mortgagebonds then outstanding and on the prospective issue of new first mortgagebonds. Our earnings for the twelve months ended March 31, 2010 wouldpermit us to issue approximately $276.4 million of new first mortgage bondsbased on this test with an assumed interest rate of 7.0%. In addition to theinterest coverage requirement, the EDE Mortgage provides that new bonds must beissued against, among other things, retired bonds or 60% of net propertyadditions. At March 31, 2010, we had retired bonds and net propertyadditions which would enable the issuance of at least $660.6 million principalamount of bonds if the annual interest requirements are met. As of March 31,2010, we are in compliance with all restrictive covenants of the EDE Mortgage.

 

Theprincipal amount of all series of first mortgage bonds outstanding at any onetime under the EDG Mortgage is limited by terms of the mortgage to $300million. Substantially all of the property, plant and equipment of The EmpireDistrict Gas Company is subject to the lien of the EDG Mortgage. The EDGMortgage contains a requirement that for new first mortgage bonds to be issued,the amount of such new first mortgage bonds shall not exceed 75% of the cost ofproperty additions acquired after the date of the Missouri Gas acquisition. Themortgage also contains a limitation on the issuance by EDG of debt (includingfirst mortgage bonds, but excluding short-term debt incurred in the ordinarycourse under working capital facilities) unless, after giving effect to such issuance,EDG’s ratio of EBITDA (defined as net income plus interest, taxes,depreciation, amortization and certain other non-cash charges) to interestcharges for the most recent four fiscal quarters is at least 2.0 to 1.****As of March 31,2010, this test would allow us to issue approximately $4.7 million principalamount of new first mortgage bonds.

 

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

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

 

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*Notrated

 

OnMarch 24, 2010, Standard & Poor’s issued a report with ourratings unchanged and upgraded our business profile to “excellent” from “strong”.On May 12, 2008, Moody’s affirmed our ratings with a negative outlook. On January 22,2010, Fitch Ratings downgraded our trust preferred securities from BBB- to BB+as a result of Fitch’s recently revised guidelines for rating preferred stockand hybrid securities issued by companies in all sectors. On April 1,2010, Fitch affirmed our ratings and revised their rating outlook to stable.The revision took into consideration the anticipated completion of ourfive-year baseload capital expenditure program in 2010 and assumes we willreceive timely and adequate regulatory recovery of newly completed investments.

 

A security rating is not a recommendation tobuy, sell or hold securities. Each rating is subject to revision or withdrawalat any time by the assigning rating organization. Each security rating agencyhas its own methodology for assigning ratings, and, accordingly, each ratingshould be considered independently of all other ratings.

 

**CONTRACTUAL OBLIGATIONS**

 

Our contractual obligationshave not significantly changed at March 31, 2010, compared to December 31,2009. We have accepted a binding proposal in the first quarter of 2010 totransport coal beginning June 30, 2010, which replaces an existingcontract that expires June 29, 2010. The proposal term is for six andone-half years and the minimum payments total approximately $91.0 million,subject to final contract terms.

 

**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, 2010, our retained earnings balance was $6.3 million,compared to $13.6 million as of March 31, 2009, after paying out $12.3million in dividends during the first quarter of 2010. A reduction of ourdividend per share, partially or in whole, could have an adverse effect on ourcommon stock price. On April 29, 2010, the Board of Directors declared aquarterly dividend of $0.32 per share on common stock payable June 15,2010 to holders of record as of June 1, 2010.

 

Our diluted earnings pershare were $0.22 for the quarter ended March 31, 2010 and were $1.18 and$1.17 for the years ended December 31, 2009 and 2008, respectively.Dividends paid per share were $0.32 for the three months ended March 31,2010 and $1.28 for each of the years ended December 31, 2009 and 2008.

 

UnderKansas corporate law, our Board of Directors may only declare and pay dividendsout of our surplus or, if there is no surplus, out of our net profits for thefiscal year in which the dividend is declared or the preceding fiscal year, orboth. Our surplus, under Kansas law, is equal to our retained earnings plusaccumulated other comprehensive income/(loss), net of income tax. However,Kansas law does permit, under certain circumstances, our Board of Directors totransfer amounts from capital in excess of par value to surplus. In addition, Section 305(a) ofthe Federal Power Act (FPA) prohibits the payment by a utility of dividendsfrom any funds “properly included in capital account”. There are no additional rules orregulations issued by the FERC under the FPA clarifying the meaning of thislimitation. However, several decisions by the FERC on specific dividendproposals suggest that any

 

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determinationwould be based on a fact-intensive analysis of the specific facts andcircumstances surrounding the utility and the dividend in question, withparticular focus on the impact of the proposed dividend on the liquidity andfinancial condition of the utility.

 

Inaddition, the EDE Mortgage and our Restated Articles contain certain dividendrestrictions. The most restrictive of these is contained in the EDE Mortgage,which provides that we may not declare or pay any dividends (other thandividends payable in shares of our common stock) or make any other distributionon, or purchase (other than with the proceeds of additional common stock financing)any shares of, our common stock if the cumulative aggregate amount thereofafter August 31, 1944 (exclusive of the first quarterly dividend of $98,000paid after said date) would exceed the sum of $10.75 million and the earnedsurplus (as defined in the EDE Mortgage) accumulated subsequent to August 31,1944, or the date of succession in the event that another corporation succeedsto our rights and liabilities by a merger or consolidation. On March 11,2008, we amended the EDE Mortgage in order to provide us with more flexibilityto pay dividends to our shareholders by increasing the basket available to paydividends by $10.75 million, as described above. As of March 31, 2010,this restriction did not prevent us from issuing dividends.

 

Inaddition, under certain circumstances, our Junior Subordinated Debentures,8-1/2% Series due 2031, reflected as Company obligated mandatorilyredeemable trust preferred securities of subsidiary holding solely parentdebentures on our balance sheet at March 31, 2010 and as a note payable tosecuritization trust on our balance sheet at December 31, 2009, held byEmpire District Electric Trust I, a consolidated 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 ofany obligations 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, 2010, there were no suchrestrictions on our ability to pay dividends.

 

**OFF-BALANCE SHEET ARRANGEMENTS**

 

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

 

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 31,2009 for a discussion of additional critical accounting policies. There were nochanges in these policies in the quarter ended March 31, 2010.

 

**RECENTLY ISSUED ACCOUNTING STANDARDS**

 

See Note 2 of “Notes toConsolidated Financial Statements (Unaudited)”.

 

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

 

Our fuel procurement activities involve primary market risk exposures,including commodity price risk and credit risk. Commodity price risk is thepotential adverse price impact related to the fuel procurement for ourgenerating units. Credit risk is the potential adverse financial impactresulting from non-performance by a counterparty of its contractualobligations. Additionally, we are exposed to interest rate risk which is the potentialadverse financial impact related to changes in interest rates.

 

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*Market Risk and Hedging Activities.*

 

Prices in the wholesale power markets often are extremely volatile.This volatility impacts our cost of power purchased and our participation inenergy trades. If we were unable to generate an adequate supply of electricityfor our customers, we would attempt to purchase power from others. Suchsupplies are not always available. In addition, congestion on the transmissionsystem can limit our ability to make purchases from (or sell into) thewholesale markets.

 

We engage in physical and financial trading activities with the goalsof reducing risk from market fluctuations. In accordance with our establishedEnergy Risk Management Policy, which typically includes entering into variousderivative transactions, we attempt to mitigate our commodity market risk. Derivativesare utilized 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*.

 

We are exposed to the impact of market fluctuations in the price andtransportation costs of coal, natural gas, and electricity and employestablished policies and procedures to manage the risks associated with thesemarket fluctuations, including utilizing derivatives.

 

We satisfied 69.89% of our2009 generation fuel supply need through coal. Approximately 88% of our 2009coal supply was Western coal. We have contracts to supply a portion of the fuelfor our coal plants through 2013. These contracts satisfy approximately 98% ofour anticipated fuel requirements for 2010, 59% for 2011, 28% for 2012 and 30%of our 2013 requirements for our Asbury and Riverton coal plants. In order tomanage our exposure to fuel prices, future coal supplies will be acquired usinga combination of short-term and long-term contracts.

 

Weare exposed to changes in market prices for natural gas we must purchase to runour combustion turbine generators. Our natural gas procurement program isdesigned to manage our costs to avoid volatile natural gas prices. We enterinto physical forward and financial derivative contracts with counterpartiesrelating to our future natural gas requirements that lock in prices (withrespect to predetermined percentages of our expected future natural gas needs)in an attempt to lessen the volatility in our fuel expenditures and improvepredictability. As of April 23, 2010, 71%, or 5.2 million Dths’s, of our anticipatedvolume of natural gas usage for our electric operations for the remainder of2010 is hedged.

 

Basedon our expected natural gas purchases for our electric operations for the nexttwelve months, if average natural gas prices should increase 10% more than theprice at March 31, 2010, our natural gas cost would increase byapproximately $1.5 million based on our March 31, 2010 total hedgedpositions for the next twelve months. However, this is probable of recoverythrough fuel adjustment mechanisms. With the addition of the Missouri fueladjustment mechanism effective September 1, 2008, we now have a fuel costrecovery mechanism in all of our jurisdictions, which significantly reduces theimpact of fluctuating fuel costs.

 

Weattempt to mitigate a portion of our natural gas price risk associated with ourgas segment using physical forward purchase agreements, storage and derivativecontracts. As of March 31, 2010, we have 0.3 million Dths in storage onthe three pipelines that serve our customers. This represents 17% of ourstorage capacity. We have an additional 0.2 million Dths hedged throughfinancial derivative and physical contracts. Our long-term hedge strategy is to mitigate price volatility for ourcustomers by hedging a minimum of 50% of the current year, up to 50% of thesecond year and up to 20% of third year expected gas usage by the beginning ofthe ACA year at September 1.However, due to purchased natural gas cost recovery mechanisms for ourretail customers, fluctuations in the cost of natural gas have little effect onincome.

 

*CreditRisk*.

 

Inorder to minimize overall credit risk, we maintain credit policies, includingthe evaluation of counterparty financial condition and the use of standardizedagreements that facilitate the netting of cash flows associated with a singlecounterparty. See Note 4 of “Notes to Consolidated Financial Statements(Unaudited)” regarding agreements containing credit risk contingent features.In addition,

 

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certain counterparties make available collateral in the form of cashheld as margin deposits as a result of exceeding agreed-upon credit exposurethresholds or may be required to prepay the transaction. Conversely, we arerequired to post collateral with counterparties at certain thresholds, which istypically the result of changes in commodity prices. Amounts reported as margindeposit liabilities represent counterparty funds we hold that result fromvarious trading counterparties exceeding agreed-upon credit exposurethresholds. Amounts reported as margin deposit assets represent our funds heldon deposit for our NYMEX contracts with our broker and other financial contractswith other counterparties that resulted from us exceeding agreed-upon creditlimits established by the counterparties. The following table depicts ourmargin deposit assets at March 31, 2009 and December 31, 2008. Therewere no margin deposit liabilities at these dates.

 
| **(in millions)**      | ** ** | **March 31, 2010** | ** ** | **December 31, 2009** | ** ** |
|------------------------|------------|-------------------------|------------|----------------------------|------------|
| Margin  deposit assets |       | $                       | 4.2        |                       | $          | 2.9 |   |
|                        |            |                         |            |                            |            |  |  |

 

Ourexposure to credit risk is concentrated primarily within our fuel procurementprocess, as we transact with a smaller, less diverse group of counterpartiesand transactions may involve large notional volumes and potentially volatilecommodity prices. Below is a table showing our net credit exposure at March 31,2010, reflecting that our counterparties are exposed to Empire for the netunrealized mark-to-market losses for physical forward and financial natural gascontracts carried at fair value.

 
| **(in  millions)**                                                               |       |   |     |
|----------------------------------------------------------------------------------|------------|--------|----------|
| Net unrealized  mark-to-market losses for physical forward natural gas contracts |       | $      | 16.1     |   |
| Net  unrealized mark-to-market losses for financial natural gas contracts        |       | 6.9    |     |
| **Net credit exposure**                                                          | ** ** | **$**  | **23.0** | ** ** |

 

The$6.9 million net unrealized mark-to-market loss for financial natural gascontracts is comprised totally of $6.9 million that our counterparties areexposed to Empire for unrealized losses with no exposure to Empire ofunrealized gains from a counterparty. We are holding no collateral from anycounterparty since we are below the $10 million mark-to-market collateralthreshold in our agreements. As noted above, as of March 31, 2010, we have$4.2 million on deposit for NYMEX contract exposure to Empire, of which $4.1million represents our collateral requirement. In addition, if NYMEX gas prices decreased 25% from their March 31,2010 levels, we would be required to post an additional $2.4 million incollateral. If these prices increased 25%, our collateral requirement woulddecrease $2.7 million. Our other counterparties would not be required to postcollateral with Empire.

 

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, we enterinto contracts with various companies in the energy industry for purchases ofenergy-related commodities, including natural gas in our fuel procurementprocess.

 

*Interest Rate Risk.*

 

We are exposed to changes in interest rates as a result of financingthrough our issuance of commercial paper and other short-term debt. We manageour interest rate exposure by limiting our variable-rate exposure (applicableto commercial paper and borrowings under our unsecured credit agreement) to acertain percentage of total capitalization, as set by policy, and by monitoringthe effects of market changes in interest rates.

 

If market interest rates average 1% more in 2010 than in 2009, ourinterest expense would increase, and income before taxes would decrease by lessthan $0.3 million. This amount has been determined by considering the impact ofthe hypothetical interest rates on our highest month-end commercial paperbalance for 2009. These analyses do not consider the effects of the reducedlevel of overall economic activity that could exist in such an environment. Inthe event of a significant change in interest rates, management would likelytake actions to further mitigate its exposure to the change. However, due tothe uncertainty of the specific actions that would be taken and their possibleeffects, the sensitivity analysis assumes no changes in our financialstructure.

 

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**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, 2010.

 

There have been no changes in our internal control over financialreporting that occurred during the first quarter of 2010 that have materiallyaffected, or are reasonably likely to materially affect, our internal controlover financial reporting.

 

**PART II.  OTHER INFORMATION**

 

**Item 1.  Legal Proceedings**

 

***Platte County Levee Lawsuit***

 

OnMay 22, 2009, a suit was filed in the Circuit Court of Platte CountyMissouri by several individuals and Class Representatives alleging damages toland, structures, equipment and devastation of crops due to inappropriatemanagement of the levee system around the Iatan Generating Station, of which weare 12% owners. No procedural schedule has been established and we are unableto predict the outcome of the law suit.

 

**Item 1A.  Risk Factors.**

 

There have been no material changes to the factors disclosed in Part I,Item 1-A. Risk Factors in our Annual Report on Form 10-K for the yearended December 31, 2009.

 

**Item5.  Other Information.**

 

Forthe twelve months ended March 31, 2010, our ratio of earnings to fixedcharges was 2.21x.  See Exhibit (12)hereto.

 

**Item 6.  Exhibits.**

 

(a)           Exhibits.

 

(12)Computation of Ratio ofEarnings to Fixed Charges.

 

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

 

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

 

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

 

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

 

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

 

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**SIGNATURES**

 

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

 
|              | **THE  EMPIRE DISTRICT ELECTRIC COMPANY** |
|-------------------|-------------------------------------------|
|              | Registrant                                |
|              |                                      |
|              |                                      |
| ** **        | **By**                                    | **/s/ Gregory A. Knapp** |
|              |                                      | Gregory A. Knapp |
|              |                                      | Vice President – Finance and Chief Financial Officer |
|              |                                      |
|              |                                      |
| ** **        | **By**                                    | **/s/ Laurie A. Delano** |
|              |                                      | Laurie A. Delano |
|              |                                      | Controller, Assistant Secretary and Assistant Treasurer |
|              |                                      |
| May 6,  2010 |                                      |

 

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