Table ofContents

 

 

 

**UNITED STATESSECURITIES AND EXCHANGE COMMISSION**

**WASHINGTON, D.C. 20549**

 

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**FORM 10-Q**

 

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**(Mark One)**

 

| **x** | **Quarterly report pursuant to Section 13 or  15(d) of the Securities Exchange Act of 1934** |
|-------|--------------------------------------------------------------------------------------------------------|

 

**For the quarterly period ended June 30, 2010 or**

 

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

 

**For the transition period from                     to                     .**

 

**Commission file number: 1-3368**

 

**THEEMPIRE DISTRICT ELECTRIC COMPANY**

(Exact name ofregistrant as specified in its charter)

 

| **Kansas**

(State of Incorporation)                                                  |   | **44-0236370**

(I.R.S. Employer Identification No.) |
|---------------------------------------------------------------------------------------|--------|------------------------------------------------------|
|                                                                                  |   |                                                 |
| **602 S. Joplin Avenue,  Joplin, Missouri**

(Address of principal executive offices) |   | **64801**

(zip code)                                |

 

Registrant’stelephone number: **(417) 625-5100**

 

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

 

Indicate by check mark whether theregistrant has submitted electronically and posted on its corporate Web site,if any, every Interactive Data File required to be submitted and postedpursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) duringthe preceding 12 months (or for such shorter period that the registrant wasrequired to submit and post such files).  Yes o  No  o

 

Indicateby check mark whether the registrant is a large accelerated filer, anaccelerated filer, a non-accelerated filer, or a smaller reporting company. Seethe definitions of “large accelerated filer,” “accelerated filer” and “smallerreporting company” in Rule 12b-2 of the Exchange Act.

 

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

 

Indicate by check mark whether theregistrant is a shell company (as defined in Rule 12b-2 of the ExchangeAct).  Yes  o  No  x

 

As of August 2, 2010, 41,389,561 sharesof common stock were outstanding.

 

 

 

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Table of Contents

 

**THE EMPIRE DISTRICT ELECTRICCOMPANY**

 

**INDEX**

 
| ** **    | ** **                                                                                  | **PAGE** |
|---------------|---------------------------------------------------------------------------------------------|----------|
|          | Forward Looking Statements                                                                  | 3        |
|          |                                                                                        |     |
| Part I - | Financial  Information:                                                                     |     |
|          |                                                                                        |     |
| Item 1.       | Financial  Statements:                                                                      |     |
|          |                                                                                        |     |
|          | a.   Consolidated Statements of Income                                       | 4        |
|          |                                                                                        |     |
|          | b.   Consolidated Statements of  Comprehensive Income                        | 7        |
|          |                                                                                        |     |
|          | c.   Consolidated Balance Sheets                                             | 8        |
|          |                                                                                        |     |
|          | d.   Consolidated Statements of Cash  Flows                                  | 10       |
|          |                                                                                        |     |
|          | e.   Notes to Consolidated Financial  Statements                             | 11       |
|          |                                                                                        |     |
| Item 2.       | Management’s  Discussion and Analysis of Financial Condition and Results of Operations | 33       |
|          |                                                                                        |     |
|          | Executive  Summary                                                                          | 33       |
|          |                                                                                        |     |
|          | Results  of Operations                                                                      | 38       |
|          |                                                                                        |     |
|          | Rate Matters                                                                                | 48       |
|          |                                                                                        |     |
|          | Competition                                                                                 | 52       |
|          |                                                                                        |     |
|          | Liquidity and Capital Resources                                                             | 54       |
|          |                                                                                        |     |
|          | Contractual  Obligations                                                                    | 59       |
|          |                                                                                        |     |
|          | Dividends                                                                                   | 59       |
|          |                                                                                        |     |
|          | Off-Balance Sheet Arrangements                                                              | 60       |
|          |                                                                                        |     |
|          | Critical Accounting Policies                                                                | 60       |
|          |                                                                                        |     |
|          | Recently Issued Accounting Standards                                                        | 60       |
|          |                                                                                        |     |
| Item 3.       | Quantitative  and Qualitative Disclosures About Market Risk                                 | 60       |
|          |                                                                                        |     |
| Item 4.       | Controls and  Procedures                                                                    | 62       |
|          |                                                                                        |     |
| Part II- | Other Information:                                                                          |     |
|          |                                                                                        |     |
| Item 1.       | Legal Proceedings                                                                           | 62       |
|          |                                                                                        |     |
| Item 1A.      | Risk Factors                                                                                | 63       |
|          |                                                                                        |     |
| Item 2.       | Unregistered Sales of Equity Securities and Use  of Proceeds - (none)                       |     |
|          |                                                                                        |     |
| Item 3.       | Defaults Upon Senior Securities - (none)                                                    |     |
|          |                                                                                        |     |
| Item 5.       | Other Information                                                                           | 63       |
|          |                                                                                        |     |
| Item  6.      | Exhibits                                                                                    | 63       |
|          |                                                                                        |     |
|          | Signatures                                                                                  | 64       |

 

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**FORWARD LOOKING STATEMENTS**

 

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

 

·                  weather, business and economic conditions and other factors which mayimpact sales volumes and customer growth;

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

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

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

·                  the results of prudency and similar reviews by regulators of costs weincur, including capital expenditures and including Southwest Power Pool (SPP)regional transmission organization (RTO) expansion costs;

·                  operation of our electric generation facilities and electric and gastransmission and distribution systems, including the performance of our jointowners;

·                  the costs and other impacts resulting from natural disasters, such astornados and ice storms;

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

·                  legislation;

·                  regulation, including environmental regulation (such as NOx, SO2, mercury, ash and CO2) and health care regulation;

·                  competition, including the regional SPP energy imbalance market;

·                  electric utility restructuring, including ongoing federal activities andpotential state activities;

·                  the impact of electric deregulation on off-system sales;

·                  changes in accounting requirements;

·                  the timing of accretion estimates, and integration costs relating tocompleted and contemplated acquisitions and the performance of acquiredbusinesses;

·                  rate regulation, growth rates, discount rates, capital spending rates,terminal value calculations and other factors integral to the calculationsutilized to test the impairment of goodwill, in addition to market and economicconditions which could adversely affect the analysis and ultimately negativelyimpact earnings;

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

·                  the performance of our pension assets and other post employment benefitplan assets and the resulting impact on our related funding commitments;

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

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

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

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

·                  other circumstances affecting anticipated rates, revenues and costs.

 

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

 

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

 

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**PART I. FINANCIAL INFORMATION**

**Item1.  Financial Statements**

**THE EMPIRE DISTRICT ELECTRICCOMPANY**

**CONSOLIDATEDSTATEMENTS OF INCOME (UNAUDITED)**

 
| ** **                                                                              | ** ** | **Three Months Ended**                              | ** ** |
|-----------------------------------------------------------------------------------------|------------|---------------------------------------------------------------|------------|
| ** **                                                                              | ** ** | **June 30**                                              | ** ** |
| ** **                                                                              | ** ** | **2010**                                                      | ** ** | **2009** | ** ** |
| ** **                                                                              | ** ** | **(000’s except per share amounts)** | ** ** |
| **Operating  revenues:**                                                                | ** ** | ** **                                                    |       |   |   |
| Electric                                                                                |       | $                                                             | 106,249    |   | $ | 102,649 |   |
| Gas                                                                                     |       | 6,516                                                         |       | 7,919 |   |
| Water                                                                                   |       | 436                                                           |       | 434 |   |
| Other                                                                                   |       | 1,281                                                         |       | 1,228 |   |
|                                                                                    |       | 114,482                                                       |       | 112,230 |   |
| **Operating  revenue deductions:**                                                      |       |                                                          |       |   |   |
| Fuel and purchased  power                                                               |       | 44,255                                                        |       | 41,548 |   |
| Cost of natural gas  sold and transported                                               |       | 2,265                                                         |       | 4,211 |   |
| Regulated operating  expenses                                                           |       | 19,272                                                        |       | 18,076 |   |
| Other operating  expenses                                                               |       | 480                                                           |       | 422 |   |
| Maintenance and repairs                                                                 |       | 9,600                                                         |       | 8,925 |   |
| Depreciation and  amortization                                                          |       | 13,586                                                        |       | 12,739 |   |
| Provision for income  taxes                                                             |       | 4,439                                                         |       | 4,028 |   |
| Other taxes                                                                             |       | 6,306                                                         |       | 6,254 |   |
|                                                                                    |       | 100,203                                                       |       | 96,203 |   |
|                                                                                    |       |                                                          |       |   |   |
| **Operating  income**                                                                   |       | 14,279                                                        |       | 16,027 |   |
| **Other  income and (deductions):**                                                     | ** ** | ** **                                                    |       |   |   |
| Allowance for equity  funds used during construction                                    |       | 1,913                                                         |       | 1,229 |   |
| Interest income                                                                         |       | 52                                                            |       | 61 |   |
| Provision for other  income taxes                                                       |       | (46                                                           | )          | (19 | ) |
| Other, net                                                                              |       | (256                                                          | )          | (43 | ) |
|                                                                                    |       | 1,663                                                         |       | 1,228 |   |
| **Interest  charges:**                                                                  |       |                                                          |       |   |   |
| Long-term debt                                                                          |       | 10,083                                                        |       | 10,912 |   |
| Trust preferred  securities                                                             |       | 1,027                                                         |       | 1,062 |   |
| Short-term debt                                                                         |       | 245                                                           |       | 206 |   |
| Allowance for borrowed  funds used during construction                                  |       | (2,430                                                        | )          | (2,106 | ) |
| Other                                                                                   |       | (352                                                          | )          | (446 | ) |
|                                                                                    |       | 8,573                                                         |       | 9,628 |   |
|                                                                                    |       |                                                          |       |   |   |
| **Net  income**                                                                         |       | $                                                             | 7,369      |   | $ | 7,627 |   |
|                                                                                    |       |                                                          |       |   |   |
| Weighted average number  of common shares outstanding - basic                           |       | 40,623                                                        |       | 34,194 |   |
|                                                                                    |       |                                                          |       |   |   |
| Weighted average number  of common shares outstanding - diluted                         |       | 40,654                                                        |       | 34,223 |   |
|                                                                                    |       |                                                          |       |   |   |
| **Total  earnings per weighted average share of common stock — basic and diluted** | ** ** | **$**                                                         | **0.18**   |   | $ | 0.22 |   |
|                                                                                    |       |                                                          |       |   |   |
| **Dividends  per share of common stock**                                                | ** ** | **$**                                                         | **0.32**   |   | $ | 0.32 |   |

 

*See accompanying Notes toConsolidated Financial Statements.*

 

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**THE EMPIRE DISTRICT ELECTRICCOMPANY**

**CONSOLIDATED STATEMENTS OF INCOME(UNAUDITED)**

 
| ** **                                                                              | ** ** | **Six Months Ended**                                | ** ** |
|-----------------------------------------------------------------------------------------|------------|---------------------------------------------------------------|------------|
| ** **                                                                              | ** ** | **June 30,**                                             | ** ** |
| ** **                                                                              | ** ** | **2010**                                                      | ** ** | **2009** | ** ** |
| ** **                                                                              | ** ** | **(000’s except per share amounts)** | ** ** |
| **Operating  revenues:**                                                                | ** ** | ** **                                                    |       |   |   |
| Electric                                                                                |       | $                                                             | 219,849    |   | $ | 209,011 |   |
| Gas                                                                                     |       | 31,076                                                        |       | 36,006 |   |
| Water                                                                                   |       | 870                                                           |       | 859 |   |
| Other                                                                                   |       | 2,581                                                         |       | 2,369 |   |
|                                                                                    |       | 254,376                                                       |       | 248,245 |   |
| **Operating  revenue deductions:**                                                      |       |                                                          |       |   |   |
| Fuel and purchased  power                                                               |       | 94,939                                                        |       | 88,338 |   |
| Cost of natural gas  sold and transported                                               |       | 17,375                                                        |       | 23,519 |   |
| Regulated operating  expenses                                                           |       | 38,189                                                        |       | 35,577 |   |
| Other operating  expenses                                                               |       | 968                                                           |       | 831 |   |
| Maintenance and repairs                                                                 |       | 17,407                                                        |       | 16,592 |   |
| Depreciation and  amortization                                                          |       | 26,771                                                        |       | 25,412 |   |
| Provision for income  taxes                                                             |       | 14,328                                                        |       | 9,561 |   |
| Other taxes                                                                             |       | 14,042                                                        |       | 13,733 |   |
|                                                                                    |       | 224,019                                                       |       | 213,563 |   |
|                                                                                    |       |                                                          |       |   |   |
| **Operating  income**                                                                   |       | 30,357                                                        |       | 34,682 |   |
| **Other  income and (deductions):**                                                     |       |                                                          |       |   |   |
| Allowance for equity  funds used during construction                                    |       | 3,653                                                         |       | 2,636 |   |
| Interest income                                                                         |       | 122                                                           |       | 137 |   |
| Provision for other  income taxes                                                       |       | (91                                                           | )          | (94 | ) |
| Other, net                                                                              |       | (503                                                          | )          | 35 |   |
|                                                                                    |       | 3,181                                                         |       | 2,714 |   |
| **Interest  charges:**                                                                  |       |                                                          |       |   |   |
| Long-term debt                                                                          |       | 20,568                                                        |       | 20,547 |   |
| Trust preferred  securities                                                             |       | 2,090                                                         |       | 2,125 |   |
| Short-term debt                                                                         |       | 490                                                           |       | 786 |   |
| Allowance for borrowed  funds used during construction                                  |       | (4,845                                                        | )          | (4,303 | ) |
| Other                                                                                   |       | (720                                                          | )          | (299 | ) |
|                                                                                    |       | 17,583                                                        |       | 18,856 |   |
|                                                                                    |       |                                                          |       |   |   |
| **Net  income**                                                                         |       | $                                                             | 15,955     |   | $ | 18,540 |   |
|                                                                                    |       |                                                          |       |   |   |
| Weighted average number  of common shares outstanding - basic                           |       | 39,618                                                        |       | 34,129 |   |
|                                                                                    |       |                                                          |       |   |   |
| Weighted average number  of common shares outstanding - diluted                         |       | 39,645                                                        |       | 34,155 |   |
|                                                                                    |       |                                                          |       |   |   |
| **Total  earnings per weighted average share of common stock – basic and diluted** |       | $                                                             | 0.40       |   | $ | 0.54 |   |
|                                                                                    |       |                                                          |       |   |   |
| **Dividends  per share of common stock**                                                | ** ** | **$**                                                         | **0.64**   |   | $ | 0.64 |   |

 

*See accompanying Notes toConsolidated Financial Statements.*

 

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**THE EMPIRE DISTRICT ELECTRICCOMPANY**

**CONSOLIDATED STATEMENTS OF INCOME(UNAUDITED)**

 
| ** **                                                                    | ** ** | **Twelve Months Ended**                             | ** ** |
|-------------------------------------------------------------------------------|------------|---------------------------------------------------------------|------------|
| ** **                                                                    | ** ** | **June 30,**                                             | ** ** |
| ** **                                                                    | ** ** | **2010**                                                      | ** ** | **2009** | ** ** |
| ** **                                                                    | ** ** | **(000’s except per share amounts)** | ** ** |
| **Operating  revenues:**                                                      | ** ** | ** **                                                    |       |   |   |
| Electric                                                                      |       | $                                                             | 443,971    |   | $ | 446,671 |   |
| Gas                                                                           |       | 52,384                                                        |       | 65,020 |   |
| Water                                                                         |       | 1,774                                                         |       | 1,764 |   |
| Other                                                                         |       | 5,170                                                         |       | 4,727 |   |
|                                                                          |       | 503,299                                                       |       | 518,182 |   |
| **Operating  revenue deductions:**                                            |       |                                                          |       |   |   |
| Fuel and purchased  power                                                     |       | 188,629                                                       |       | 188,511 |   |
| Cost of natural gas  sold and transported                                     |       | 29,457                                                        |       | 43,151 |   |
| Regulated operating  expenses                                                 |       | 75,698                                                        |       | 71,934 |   |
| Other operating  expenses                                                     |       | 1,937                                                         |       | 1,895 |   |
| Maintenance and repairs                                                       |       | 33,827                                                        |       | 32,748 |   |
| Depreciation and  amortization                                                |       | 52,853                                                        |       | 51,491 |   |
| Provision for income  taxes                                                   |       | 24,338                                                        |       | 23,600 |   |
| Other taxes                                                                   |       | 26,390                                                        |       | 26,043 |   |
|                                                                          |       | 433,129                                                       |       | 439,373 |   |
|                                                                          |       |                                                          |       |   |   |
| **Operating  income**                                                         |       | 70,170                                                        |       | 78,809 |   |
| **Other  income and (deductions):**                                           |       |                                                          |       |   |   |
| Allowance for equity  funds used during construction                          |       | 7,225                                                         |       | 5,950 |   |
| Interest income                                                               |       | 202                                                           |       | 572 |   |
| Benefit (provision) for  other income taxes                                   |       | (308                                                          | )          | 178 |   |
| Other, net                                                                    |       | (997                                                          | )          | (1,073 | ) |
|                                                                          |       | 6,122                                                         |       | 5,627 |   |
| **Interest  charges:**                                                        | ** ** | ** **                                                    |       |   |   |
| Long-term debt                                                                |       | 42,106                                                        |       | 39,677 |   |
| Trust preferred  securities                                                   |       | 4,215                                                         |       | 4,250 |   |
| Short-term debt                                                               |       | 828                                                           |       | 1,796 |   |
| Allowance for borrowed  funds used during construction                        |       | (8,466                                                        | )          | (8,029 | ) |
| Other                                                                         |       | (1,102                                                        | )          | 287 |   |
|                                                                          |       | 37,581                                                        |       | 37,981 |   |
|                                                                          |       |                                                          |       |   |   |
| **Net  income**                                                               |       | $                                                             | 38,711     |   | $ | 46,455 |   |
|                                                                          |       |                                                          |       |   |   |
| Weighted average number  of common shares outstanding — basic            |       | 37,645                                                        |       | 34,025 |   |
| Weighted average number  of common shares outstanding — diluted          |       | 37,665                                                        |       | 34,067 |   |
|                                                                          |       |                                                          |       |   |   |
| **Total  earnings per weighted average share of common stock — basic**   |       | $                                                             | 1.03       |   | $ | 1.37 |   |
| **Total  earnings per weighted average share of common stock — diluted** |       | $                                                             | 1.03       |   | $ | 1.36 |   |
| **Dividends  per share of common stock**                                      | ** ** | **$**                                                         | **1.28**   |   | $ | 1.28 |   |

 

*See accompanying Notes toConsolidated Financial Statements.*

 

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**THE EMPIRE DISTRICT ELECTRICCOMPANY**

**CONSOLIDATEDSTATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)**

 
| ** **                                                                                                      | ** ** | **Three Months Ended** | ** ** |
|-----------------------------------------------------------------------------------------------------------------|------------|----------------------------------|------------|
| ** **                                                                                                      | ** ** | **June 30,**                | ** ** |
| ** **                                                                                                      | ** ** | **2010**                         | ** ** | **2009** | ** ** |
| ** **                                                                                                      | ** ** | **($-000’s)**               | ** ** |
|                                                                                                            |       |                             |       |   |   |
| **Net  income**                                                                                                 |       | $                                | 7,369      |   | $ | 7,627 |   |
| Reclassification  adjustments for loss included in net income or reclassified to regulatory  asset or liability |       | 950                              |       | 1,739 |   |
| Net change in fair  market value of derivative contracts for period                                             |       | 676                              |       | 1,866 |   |
| Income taxes                                                                                                    |       | (619                             | )          | (1,374 | ) |
|                                                                                                            |       |                             |       |   |   |
| **Comprehensive  income**                                                                                       |       | $                                | 8,376      |   | $ | 9,858 |   |

 
| ** **                                                                                                      | ** ** | **Six Months Ended** | ** ** |
|-----------------------------------------------------------------------------------------------------------------|------------|--------------------------------|------------|
| ** **                                                                                                      | ** ** | **June 30,**              | ** ** |
| ** **                                                                                                      | ** ** | **2010**                       | ** ** | **2009** | ** ** |
| ** **                                                                                                      | ** ** | **($-000’s)**             | ** ** |
|                                                                                                            |       |                           |       |   |   |
| **Net  income**                                                                                                 |       | $                              | 15,955     |   | $ | 18,540 |   |
| Reclassification  adjustments for loss included in net income or reclassified to regulatory  asset or liability |       | 950                            |       | 6,665 |   |
| Net change in fair  market value of derivative contracts for period                                             |       | (5,325                         | )          | (7,467 | ) |
| Income taxes                                                                                                    |       | 1,667                          |       | 306 |   |
|                                                                                                            |       |                           |       |   |   |
| **Comprehensive  income**                                                                                       |       | $                              | 13,247     |   | $ | 18,044 |   |

 
| ** **                                                                                                      | ** ** | **Twelve Months Ended** | ** ** |
|-----------------------------------------------------------------------------------------------------------------|------------|-----------------------------------|------------|
| ** **                                                                                                      | ** ** | **June 30,**                 | ** ** |
| ** **                                                                                                      | ** ** | **2010**                          | ** ** | **2009** | ** ** |
| ** **                                                                                                      | ** ** | **($-000’s)**                | ** ** |
|                                                                                                            |       |                              |       |   |   |
| **Net  income**                                                                                                 |       | $                                 | 38,711     |   | $ | 46,455 |   |
| Reclassification  adjustments for loss included in net income or reclassified to regulatory  asset or liability |       | 7,853                             |       | 5,365 |   |
| Net change in fair  market value of derivative contracts for period                                             |       | (7,434                            | )          | (58,689 | ) |
| Income taxes                                                                                                    |       | (160                              | )          | 20,316 |   |
|                                                                                                            |       |                              |       |   |   |
| **Comprehensive  income**                                                                                       |       | $                                 | 38,970     |   | $ | 13,447 |   |

 

*See accompanying Notes toConsolidated Financial Statements***.**

 

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**THE EMPIRE DISTRICT ELECTRICCOMPANY**

**CONSOLIDATED BALANCE SHEETS (UNAUDITED)**

 
| ** **                                             | ** ** | **June 30,  2010** | ** ** | **December  31, 2009** | ** ** |
|--------------------------------------------------------|------------|--------------------|------------|------------------------|------------|
| ** **                                             | ** ** | **($-000’s)** | ** ** |
| **Assets**                                             |       |               |       |                   |       |
| Plant  and property, at original cost:                 |       |               |       |                   |       |
| Electric                                               |       | $                  | 1,653,852  |                   | $          | 1,619,949 |   |
| Natural  gas                                           |       | 58,987             |       | 58,180                 |       |
| Water                                                  |       | 11,053             |       | 10,891                 |       |
| Other                                                  |       | 30,702             |       | 29,564                 |       |
| Construction  work in progress                         |       | 321,746            |       | 302,012                |       |
|                                                   |       | 2,076,340          |       | 2,020,596              |       |
| Accumulated  depreciation and amortization             |       | 580,701            |       | 561,586                |       |
|                                                   |       | 1,495,639          |       | 1,459,010              |       |
|                                                   |       |               |       |                   |       |
| **Current assets:**                                    |       |               |       |                   |       |
| Cash  and cash equivalents                             |       | 6,728              |       | 5,620                  |       |
| Accounts  receivable — trade, net                 |       | 37,873             |       | 36,136                 |       |
| Accrued  unbilled revenues                             |       | 20,088             |       | 23,717                 |       |
| Accounts  receivable — other                      |       | 15,900             |       | 21,417                 |       |
| Fuel,  materials and supplies                          |       | 45,564             |       | 43,973                 |       |
| Unrealized  gain in fair value of derivative contracts |       | 419                |       | 2,782                  |       |
| Prepaid  expenses and other                            |       | 6,950              |       | 4,438                  |       |
| Regulatory  assets                                     |       | 3,456              |       | 772                    |       |
|                                                   |       | 136,978            |       | 138,855                |       |
|                                                   |       |               |       |                   |       |
| **Noncurrent assets and deferred charges:**            | ** ** | ** **         |       |                   |       |
| Regulatory  assets                                     |       | 167,090            |       | 168,254                |       |
| Goodwill                                               |       | 39,492             |       | 39,492                 |       |
| Unamortized  debt issuance costs                       |       | 9,841              |       | 10,638                 |       |
| Unrealized  gain in fair value of derivative contracts |       | 713                |       | 2,525                  |       |
| Iatan  investment tax credits                          |       | 17,713             |       | 17,713                 |       |
| Other                                                  |       | 2,227              |       | 3,359                  |       |
|                                                   |       | 237,076            |       | 241,981                |       |
| **Total Assets**                                       |       | $                  | 1,869,693  |                   | $          | 1,839,846 |   |

 

(Continued)

 

*See accompanying Notes toConsolidated Financial Statements***.**

 

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**THE EMPIRE DISTRICT ELECTRICCOMPANY**

**CONSOLIDATED BALANCE SHEETS(UNAUDITED) (Continued)**

 
| ** **                                                                                          | ** ** | **June 30,  2010** | ** ** | **December 31,  2009** | ** ** |
|-----------------------------------------------------------------------------------------------------|------------|-------------------------|------------|-----------------------------|------------|
| ** **                                                                                          | ** ** | **($-000’s)**      | ** ** |
| **Capitalization and Liabilities**                                                                  |       |                    |       |                        |       |
| Common  stock, $1 par value, 41,362,758 and 38,112,280 shares issued and outstanding,  respectively |       | $                       | 41,363     |                        | $          | 38,112 |   |
| Capital  in excess of par value                                                                     |       | 605,860                 |       | 551,631                     |       |
| Retained  earnings                                                                                  |       | 559                     |       | 10,068                      |       |
| Accumulated  other comprehensive (loss)/income, net of income tax                                   |       | (2,369                  | )          | 339                         |       |
| **Total common stockholders’ equity**                                                          |       | 645,413                 |       | 600,150                     |       |
|                                                                                                |       |                    |       |                        |       |
| **Long-term debt (net of current portion):**                                                        |       |                    |       |                        |       |
| Note  payable to securitization trust                                                               |       | —                  |       | 50,000                      |       |
| Obligations  under capital lease                                                                    |       | 2,489                   |       | 2,563                       |       |
| First  mortgage bonds and secured debt                                                              |       | 439,096                 |       | 339,643                     |       |
| Unsecured  debt                                                                                     |       | 247,815                 |       | 247,950                     |       |
| **Total long-term debt**                                                                            |       | 689,400                 |       | 640,156                     |       |
| **Total long-term debt and common stockholders’ equity**                                       |       | 1,334,813               |       | 1,240,306                   |       |
|                                                                                                |       |                    |       |                        |       |
| **Current liabilities:**                                                                            |       |                    |       |                        |       |
| Accounts  payable and accrued liabilities                                                           |       | 46,640                  |       | 67,406                      |       |
| Current  maturities of long-term debt                                                               |       | 865                     |       | 51,021                      |       |
| Short-term  debt                                                                                    |       | 40,000                  |       | 50,500                      |       |
| Customer  deposits                                                                                  |       | 10,535                  |       | 10,394                      |       |
| Interest  accrued                                                                                   |       | 5,470                   |       | 5,698                       |       |
| Unrealized  loss in fair value of derivative contracts                                              |       | 4,365                   |       | 4,337                       |       |
| Taxes  accrued                                                                                      |       | 11,873                  |       | 3,386                       |       |
|                                                                                                |       | 119,748                 |       | 192,742                     |       |
| **Commitments and contingencies (Note 7)**                                                          |       |                    |       |                        |       |
| **Noncurrent liabilities and deferred credits:**                                                    |       |                    |       |                        |       |
| Regulatory  liabilities                                                                             |       | 83,897                  |       | 87,533                      |       |
| Deferred  income taxes                                                                              |       | 204,180                 |       | 194,315                     |       |
| Unamortized  investment tax credits                                                                 |       | 19,977                  |       | 20,125                      |       |
| Pension  and other postretirement benefit obligations                                               |       | 86,640                  |       | 84,240                      |       |
| Unrealized  loss in fair value of derivative contracts                                              |       | 1,925                   |       | 426                         |       |
| Other                                                                                               |       | 18,513                  |       | 20,159                      |       |
| ** **                                                                                          |       | 415,132                 |       | 406,798                     |       |
| **Total Capitalization and Liabilities**                                                            |       | $                       | 1,869,693  |                        | $          | 1,839,846 |   |

 

*See accompanying Notes toConsolidated Financial Statements.*

 

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**THE EMPIRE DISTRICT ELECTRICCOMPANY**

**CONSOLIDATEDSTATEMENTS OF CASH FLOWS (UNAUDITED)**

 
| ** **                                                                        | ** ** | **Six Months Ended** | ** ** |
|-----------------------------------------------------------------------------------|------------|----------------------|------------|
| ** **                                                                        | ** ** | **June 30,**    | ** ** |
| ** **                                                                        | ** ** | **2010**             | ** ** | **2009** | ** ** |
| ** **                                                                        | ** ** | **($-000’s)**   | ** ** |
| **Operating  activities:**                                                        | ** ** | ** **           |       |   |   |
| Net income                                                                        |       | $                    | 15,955     |   | $ | 18,540 |   |
| **Adjustments  to reconcile net income to cash flows from operating activities**: |       |                 |       |   |   |
| Depreciation and  amortization                                                    |       | 30,698               |       | 29,903 |   |
| Pension and other  postretirement benefit costs                                   |       | 3,060                |       | 2,803 |   |
| Deferred income taxes  and unamortized investment tax credit, net                 |       | 4,097                |       | 5,321 |   |
| Allowance for equity  funds used during construction                              |       | (3,653               | )          | (2,636 | ) |
| Stock compensation  expense                                                       |       | 1,670                |       | 1,398 |   |
| Non-cash loss on  derivatives                                                     |       | 652                  |       | 6,034 |   |
| Gain on sale of assets                                                            |       | —               |       | (504 | ) |
| **Cash  flows impacted by changes in:**                                           |       |                 |       |   |   |
| Accounts receivable and  accrued unbilled revenues                                |       | 6,246                |       | 6,714 |   |
| Fuel, materials and  supplies                                                     |       | (1,591               | )          | 8,077 |   |
| Prepaid expenses, other  current assets and deferred charges                      |       | (5,879               | )          | (3,111 | ) |
| Accounts payable and  accrued liabilities                                         |       | (18,806              | )          | (21,462 | ) |
| Customer deposits,  interest and taxes accrued                                    |       | 8,400                |       | 7,940 |   |
| Other liabilities and  other deferred credits                                     |       | 1,137                |       | 968 |   |
|                                                                              |       |                 |       |   |   |
| **Net  cash provided by operating activities**                                    |       | 41,986               |       | 59,985 |   |
| ** **                                                                        | ** ** | ** **           | ** ** | ** ** | ** ** |
| **Investing  activities:**                                                        | ** ** | ** **           | ** ** | ** ** | ** ** |
| Capital expenditures —  regulated                                            |       | (57,200              | )          | (83,613 | ) |
| Capital expenditures  and other investments — non-regulated                  |       | (2,004               | )          | (876 | ) |
| Proceeds from the sale  of property, plant and equipment                          |       | —               |       | 544 |   |
|                                                                              |       |                 |       |   |   |
| **Net  cash used in investing activities**                                        |       | (59,204              | )          | (83,945 | ) |
|                                                                              |       |                 |       |   |   |
| **Financing  activities:**                                                        | ** ** | ** **           |       |   |   |
| Proceeds from first  mortgage bonds, net                                          |       | 99,786               |       | 75,000 |   |
| Proceeds from notes  payable                                                      |       | —               |       | 1,431 |   |
| Long-term debt issuance  costs                                                    |       | (924                 | )          | (2,396 | ) |
| Proceeds from issuance  of common stock net of issuance costs                     |       | 56,178               |       | 2,589 |   |
| Repayment of First  Mortgage Bonds                                                |       | (50,000              | )          | — |   |
| Redemption of Trust  Preferred Securities                                         |       | (50,000              | )          | — |   |
| Net short-term debt  repayments                                                   |       | (10,500              | )          | (30,000 | ) |
| Dividends                                                                         |       | (25,464              | )          | (21,859 | ) |
| Other                                                                             |       | (750                 | )          | (168 | ) |
|                                                                              |       |                 |       |   |   |
| **Net  cash provided by financing activities**                                    |       | 18,326               |       | 24,597 |   |
|                                                                              |       |                 |       |   |   |
| **Net  increase in cash and cash equivalents**                                    |       | 1,108                |       | 637 |   |
|                                                                              |       |                 |       |   |   |
| **Cash  and cash equivalents at beginning of period**                             |       | 5,620                |       | 2,754 |   |
|                                                                              |       |                 |       |   |   |
| **Cash  and cash equivalents at end of period**                                   |       | $                    | 6,728      |   | $ | 3,391 |   |

 

*See accompanying Notes toConsolidated Financial Statements.*

 

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**NOTES TO CONSOLIDATED FINANCIALSTATEMENTS (UNAUDITED)**

 

**Note 1 - Summary of Significant AccountingPolicies**

 

We operate our businesses as three segments:  electric, gas and other. The Empire DistrictElectric Company (EDE), a Kansas corporation organized in 1909, is an operatingpublic utility engaged in the generation, purchase, transmission, distributionand sale of electricity in parts of Missouri, Kansas, Oklahoma and Arkansas. Aspart of our electric segment, we also provide water service to three towns inMissouri. The Empire District Gas Company (EDG) is our wholly-owned subsidiarywhich provides natural gas distribution to communities in northwest, northcentral and west central Missouri. Our other segment consists of our fiberoptics business.

 

The accompanying interim financial statements donot include all disclosures included in the annual financial statements andtherefore should be read in conjunction with the financial statements and notesthereto included in our Annual Report on Form 10-K for the fiscal yearended December 31, 2009.

 

The information furnished reflects alladjustments, consisting only of normal recurring adjustments, which are in ouropinion necessary to state fairly the results for the interim periods as wellas present these periods on a consistent basis with the financial statementsfor the fiscal year ended December 31, 2009, of which there were none.

 

**Note 2 - Recently Issued and Proposed AccountingStandards**

 

*Fair Value.***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.***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 (VIE).Additionally, the amendment requires additional disclosures, and an ongoingreassessment of who must consolidate a VIE. A controlling financial interest isrequired for a VIE and this is evidenced by either a voting interest greaterthan 50% or a risk and reward model that identifies EDE as the primarybeneficiary of a VIE.

 

Upon adoption of the guidance, we concluded thatthe consolidation of the Empire District Electric Trust I was appropriate andwe reflected it in our consolidated balance sheets in the first quarter of2010. Subsequently, on June 28, 2010, we redeemed all 2 million outstandingshares of our 8.5% trust preferred securities held by the Trust.

 

We also evaluated our long-term purchase poweragreements to determine if we hold a variable interest. This evaluationidentified our purchase power agreement for capacity from Plum Point EnergyStation as a variable interest. For this contract we considered operations andmaintenance of the power plant to be the most significant activity. Inaddition, 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. The adoption of this standard did not have a material impact on our financialstatements.

 

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See Note 1 under “Notes to Consolidated FinancialStatements” in our Annual Report on Form 10-K for the year ended December 31,2009 for further information regarding recently issued accounting standards.

 

**Note 3— Regulatory Matters**

 

The following table sets forth the components ofour regulatory assets and liabilities on our consolidated balance sheet (inthousands).

 

**Regulatory Assets and Liabilities**

 
| ** **                                                              | ** ** | **June 30, 2010** | ** ** | **December 31, 2009** | ** ** |
|-------------------------------------------------------------------------|------------|------------------------|------------|----------------------------|------------|
| **Regulatory  Assets:**                                                 |       |                   |       |                       |       |
| Under recovered  purchased gas costs — gas segment, current        |       | $                      | 201        |                       | $          | 434 |   |
| Under recovered  electric fuel and purchased power costs — current |       | 3,255                  |       | 338                        |       |
| Regulatory assets,  current**(1)**                                      |       | $                      | 3,456      |                       | $          | 772 |   |
| Pension and other  postretirement benefits**(2)**                       |       | 79,214                 |       | 81,171                     |       |
| Income taxes                                                            |       | 47,962                 |       | 49,230                     |       |
| Unamortized loss on  reacquired debt                                    |       | 12,799                 |       | 12,167                     |       |
| Unamortized loss on  interest rate derivative                           |       | 1,934                  |       | 2,091                      |       |
| Asbury five-year  maintenance                                           |       | 1,173                  |       | 1,401                      |       |
| Ice storm costs**(3)**                                                  |       | 9,800                  |       | 11,673                     |       |
| Deferred Iatan  construction accounting costs**(4)**                    |       | 5,196                  |       | 2,732                      |       |
| Asset retirement  obligation                                            |       | 3,343                  |       | 3,264                      |       |
| Under recovered  electric fuel and purchased power costs                |       | 127                    |       | 662                        |       |
| Unsettled derivative  losses — electric segment                    |       | 1,524                  |       | 335                        |       |
| Customer programs                                                       |       | 1,430                  |       | 1,255                      |       |
| System reliability —  vegetation management                        |       | 1,648                  |       | 1,636                      |       |
| Other                                                                   |       | 940                    |       | 637                        |       |
| Regulatory assets,  long-term                                           |       | $                      | 167,090    |                       | $          | 168,254 |   |
| **Total**                                                               |       | $                      | 170,546    |                       | $          | 169,026 |   |

 
| ** **                                                     | ** ** | **June 30, 2010** | ** ** | **December 31, 2009** | ** ** |
|----------------------------------------------------------------|------------|------------------------|------------|----------------------------|------------|
| **Regulatory  Liabilities:**                                   |       |                   |       |                       |       |
| Cost of removal                                                |       | $                      | 57,790     |                       | $          | 53,083 |   |
| Income taxes                                                   |       | 13,122                 |       | 20,678                     |       |
| Unamortized gain on  interest rate derivative                  |       | 3,966                  |       | 4,051                      |       |
| Pension and other  postretirement benefits**(5)**              |       | 5,761                  |       | 6,415                      |       |
| Over recovered electric  fuel and purchased power costs**(6)** |       | 452                    |       | 1,344                      |       |
| Over recovered  purchased gas costs — gas segment         |       | 2,718                  |       | 1,874                      |       |
| Other                                                          |       | 88                     |       | 88                         |       |
| **Total**                                                      |       | $                      | 83,897     |                       | $          | 87,533 |   |

 

----

(1) Reflects under recovered costs expected tobe recovered within the next 12 months in Missouri rates.

(2) Primarily reflects regulatory assetsresulting from the unfunded portion of our pension and OPEB liabilities andregulatory accounting for EDG acquisition costs. Approximately $0.3 million inpension and other postretirement benefit costs have been recognized since January 1,2010 to reflect the amortization of the regulatory assets that were recorded atthe time of the EDG acquisition.

(3) Primarily reflects ice storm costsincurred in 2007 currently being recovered and amortized over a five yearperiod, but also includes deferred wind storm costs of $0.7 million incurred inMay 2009, which will be recovered over a five year period commencing in September 2010.

(4) Includes $1.5 million of deferred depreciationcosts and $3.7 million in carrying costs related to construction accounting forIatan 1 recorded since April 19, 2009, in accordance with our regulatoryplan. The effect of these deferred carrying charges is reflected in regulatedoperating expenses, depreciation and in other interest on the statement ofoperations. Construction accounting, for purposes of the regulatory plan, isspecific to Iatan 1 and Iatan 2 construction and allows us to defer certaincharges as regulatory assets, including depreciation and carrying costs,related to operation of the facilities until the facilities are ultimatelyincluded in our rate base. The amounts deferred, which began at the in-servicedate for Iatan 1 and will also be deferred for Iatan 2 at its in-service date,will then be amortized over the life of the plants once they are in our ratebase.

(5) Includes the effect of costs incurred thatare more or less than those allowed in rates for the Missouri (EDE and EDG) andKansas (EDE) portion of pension costs and the Missouri EDE portion of otherpostretirement benefit costs. Since

 

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January 1, 2010, regulatory liabilities andcorresponding expenses have been reduced by approximately $0.2 million as aresult of ratemaking treatment.

(6) Primarily consists of Missouri overrecovered fuel and purchased power costs for the current accumulation period March 2010through August 2010.

 

There have been no changes to regulatory assets andliabilities regarding their rate base inclusion or amortizable lives since December 31,2009 other than the write off of approximately $1.2 million of tax amortizationin the first quarter of 2010 which we estimated rate recovery would no longerbe probable for. See Note 12 — Income Taxes for additional information.

 

**Note 4— Risk Management and Derivative Financial Instruments**

 

We engage in hedging activities in an effort tominimize our risk from volatile natural gas prices. We enter into both physicaland financial contracts with counterparties relating to our future natural gasrequirements that lock in prices (with respect to a range of predeterminedpercentages of our expected future natural gas needs) in an attempt to lessenthe volatility in our fuel expenditures and gain predictability. We recognizethat if risk is not timely and adequately balanced or if counterparties fail toperform contractual obligations, actual results could differ materially fromintended results.

 

All derivative instruments are recognized at fairvalue on the balance sheet with unrealized gains and losses deferred in othercomprehensive income (in stockholders’ equity) for effective instrumentsrelated to our electric segment, entered into prior to September 1, 2008.All other instruments’ unrealized gains and losses are deferred as a regulatoryasset or liability, due to our Missouri fuel recovery mechanism, effective September 1,2008 for our electric segment, and for our gas segment. For all our derivativecontracts, once settled, the realized gain or loss is recorded to fuel expenseand subject to our fuel adjustment clause mechanism, which permits thedistribution to customers of 95% of the changes in fuel and purchased powercosts prudently incurred above or below the base cost.

 

For those electric instruments entered into priorto September 1, 2008, we record unrealized gains/(losses) on theineffective portion of our gas hedging activities in “Fuel and purchased power”under the operating revenue deductions section of our Statement of Income sinceall of our gas hedging activities are related to stabilizing fuel costs as partof our fuel procurement program and are not speculative activities. Risks anduncertainties affecting the determination of fair value include:  market conditions in the energy industry,especially the effects of price volatility, regulatory and global politicalenvironments and requirements, fair value estimations on longer term contracts,the effectiveness of the derivative instrument in hedging the change in fairvalue of the hedged item, estimating underlying fuel demand and counterpartyability to perform. If we estimate that we have overhedged forecasted demand,the gain or loss on the overhedged portion will be recognized immediately asfuel and purchased power expense in our Consolidated Statement of Income.

 

As of June 30, 2010 and December 31,2009, we have recorded the following assets and liabilities representing thefair value of derivative financial instruments, (in thousands):

 

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| **ASSET DERIVATIVES**                           | ** ** | **June 30,**                          | ** ** | **December 31,** | ** ** |
|------------------------------------------------------|------------|--------------------------------------------|------------|-----------------------|------------|
| **Derivatives designated as hedging** | ** ** | ** **                                 | ** ** | **2010**              | ** ** | **2009** | ** ** |
| **instruments**                                      | ** ** | **Balance Sheet Classification** | ** ** | **Fair Value**   | ** ** | **Fair Value** | ** ** |
| Natural gas contracts,  electric segment             |       | Current assets                             |       | $                     | 412        |   | $ | 2,233 |   |
|                                                 |       | Non-current assets and deferred charges    |       | 680                   |       | 2,438 |   |
|                                                      |            |                                            |            |                       |            |  |  |  |  |

 
| **Derivatives not designated as hedging********instruments due to regulatory accounting** | ** ** | ** **                              | ** ** | ** ** | ** ** | ** ** | ** ** |
|-----------------------------------------------------------------------------------------------------------------------------------|------------|-----------------------------------------|------------|------------|------------|------------|------------|
| Natural gas contracts,  gas segment                                                                                               |       | Current assets                          |       | 7          |       | 410        |       |
|                                                                                                                              |       |                                    |       |       |       |       |       |
| Natural gas contracts,  electric segment                                                                                          |       | Current assets                          |       | —     |       | 139        |       |
|                                                                                                                              |       | Non-current assets and deferred charges |       | 33         |       | 87         |       |
| **Total  derivatives assets**                                                                                                     | ** ** | ** **                              | ** ** | **$**      | **1,132**  | ** ** | **$**      | **5,307** | ** ** |
|                                                                                                                                   |            |                                         |            |            |            |            |            |  |  |

 
| **LIABILITY DERIVATIVES**                | ** ** | **June 30,**                | ** ** | **December 31,** | ** ** |
|------------------------------------------|------------|----------------------------------|------------|-----------------------|------------|
| **Derivatives  designated as hedging**   | ** ** | ** **                       | ** ** | **2010**              | ** ** | **2009** | ** ** |
| **instruments**                          | ** ** | **Balance Sheet Classification** | ** ** | **Fair Value**   | ** ** | **Fair Value** | ** ** |
| Natural gas contracts,  electric segment |       | Current liabilities              |       | $                     | 4,277      |   | $ | 4,123 |   |
|                                          |            |                                  |            |                       |            |  |  |  |  |

 
| **Derivatives not designated as hedging  instruments due to regulatory accounting** | ** ** | ** **                                   | ** ** | ** ** | ** ** | ** ** | ** ** |
|-----------------------------------------------------------------------------------------------------------------------------|------------|----------------------------------------------|------------|------------|------------|------------|------------|
| Natural gas contracts,  gas segment                                                                                         |       | Current liabilities                          |       | $          | 41         |       | $          | 214 |   |
|                                                                                                                        |       |                                         |       |       |       |       |       |
| Natural gas contracts,  electric segment                                                                                    |       | Current liabilities                          |       | 47         |       | —     |       |
|                                                                                                                        |       | Non-current liabilities and deferred credits |       | 1,925      |       | 426        |       |
| **Total  derivatives liabilities**                                                                                          | ** ** | ** **                                   | ** ** | **$**      | **6,290**  | ** ** | **$**      | **4,763** |   |

 

*Electric*

 

A $2.4 million net of tax, unrealized lossrepresenting the fair market value of our electric segment derivative contractstreated as cash flow hedges and entered into prior to September 1, 2008,is recognized as Accumulated Other Comprehensive Income in the capitalizationsection of the balance sheet as of June 30, 2010. The tax effect of $1.5million on this loss is included in deferred taxes. These amounts will beadjusted cumulatively on a monthly basis during the determination periods,beginning July 1, 2010 and ending on September 30, 2011. At the endof each determination period, or if cash flow hedge treatment is discontinued,any realized gain or loss for that period related to the instrument isreclassified to fuel expense and is subject to the fuel adjustment clause. Asof June 30, 2010, approximately $4.5 million of unrealized losses areapplicable to financial instruments which will settle within the next twelvemonths. The unrealized losses or gains from new cash flow hedges entered intoafter September 1, 2008, are recorded in regulatory assets or liabilities.This is in accordance with ASC guidance on accounting for regulated operations,given that those regulatory assets and liabilities are probable of recoverythrough our fuel adjustment mechanism. Unrealized gains and losses from cashflow hedges existing at September 1, 2008 continue to be recorded throughcomprehensive income.

 

The following tables set forth the actual pre-taxgains/(losses) and the mark to market effect of unsettled positions from thequalified portion of our hedging activities for the electric segment for eachof the periods ended June 30, (in thousands):

 
| **Derivatives in Cash Flow**      | ** ** | **Income Statement  Classification of** | ** ** | **Amount of Gain / (Loss) Reclassed from OCI into Income********(Effective portion)** | ** ** |
|--------------------------------------------------|------------|---------------------------------------------------|------------|-----------------------------------------------------------------------------------------------------------------------------------------|------------|
| **Hedging Relationships -**            | ** ** | **Gain / (Loss) on**               | ** ** | **Three Months Ended**                                                                                                        | ** ** | **Six Months Ended** | ** ** | **Twelve Months Ended** | ** ** |
| **Electric Segment**                        | ** ** | **Derivative**                                    | ** ** | **2010**                                                                                                                                | ** ** | **2009** | ** ** | **2010** | ** ** | **2009** | ** ** | **2010** | ** ** | **2009** | ** ** |
| Commodity contracts                              |       | Fuel and purchased power expense                  |       | $                                                                                                                                       | (950       | ) | $ | (1,739 | ) | $ | (950 | ) | $ | (6,665 | ) | $ | (7,853 | ) | $ | (5,365 | ) |
|                                             |       |                                              |       |                                                                                                                                    |       |   |   |   |   |   |   |   |   |   |   |
| **Total  Effective —****Electric  Segment** | ** ** | ** **                                        | ** ** | **$**                                                                                                                                   | **(950**   | **)** | **$** | **(1,739** | **)** | **$** | **(950** | **)** | **$** | **(6,665** | **)** | **$** | **(7,853** | **)** | **$** | **(5,365** | **)** |

 

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| **Derivatives in Cash  Flow Hedging** | ** ** | **Statement of**            | ** ** | **Amount of Gain / (Loss) Recognized in OCI on Derivative********(Effective portion)** | ** ** |
|------------------------------------------------------|------------|----------------------------------|------------|------------------------------------------------------------------------------------------------------------------------------------------|------------|
| **Relationships -**                             | ** ** | **Comprehensive**                | ** ** | **Three Months Ended**                                                                                                         | ** ** | **Six Months Ended** | ** ** | **Twelve Months Ended** | ** ** |
| **Electric Segment**                            | ** ** | **Income**                       | ** ** | **2010**                                                                                                                                 | ** ** | **2009** | ** ** | **2010** | ** ** | **2009** | ** ** | **2010** | ** ** | **2009** | ** ** |
| Commodity contracts                                  |       | Fuel and purchased power expense |       | $                                                                                                                                        | 676        |   | $ | 1,866 |   | $ | (5,325 | ) | $ | (7,467 | ) | $ | (7,434 | ) | $ | (58,689 | ) |
|                                                 |       |                             |       |                                                                                                                                     |       |   |   |   |   |   |   |   |   |   |   |
| **Total  Effective —****Electric  Segment**     | ** ** | ** **                       | ** ** | **$**                                                                                                                                    | **676**    | ** ** | **$** | **1,866** | ** ** | **$** | **(5,325** | **)** | **$** | **(7,467** | **)** | **$** | **(7,434** | **)** | **$** | **(58,689** | **)** |

 

The ineffective portion of our hedging activitiesfor the electric segment was insignificant for each of the periods ended June 30.

 

In accordance with the Missouri fuel adjustmentclause discussed above, the recoverable portion of any gain or loss is recordedin a regulatory asset or liability account. The following tables set forth “mark-to-market”pre-tax gains/(losses) from derivatives not designated as hedging instrumentsfor the electric segment for each of the periods ended June 30, (inthousands):

 
| **Derivatives Not  Designated as Hedging  Instruments - Due to** | ** ** | **Balance Sheet  Classification of** | ** ** | **Amount of Gain / (Loss) Recognized on Balance Sheet** | ** ** |
|------------------------------------------------------------------------------------------------|------------|------------------------------------------------|------------|-------------------------------------------------------------------------------------------------|------------|
| **Regulatory Accounting**                                                                 | ** ** | **Gain / (Loss) on**            | ** ** | **Three Months Ended**                                                                | ** ** | **Six Months Ended** | ** ** | **Twelve Months Ended** | ** ** |
| **Electric Segment(1)**                                                                   | ** ** | **Derivative**                                 | ** ** | **2010**                                                                                        | ** ** | **2009** | ** ** | **2010** | ** ** | **2009** | ** ** | **2010** | ** ** | **2009** | ** ** |
| Commodity contracts —  electric segment                                                   |       | Regulatory (assets)/liabilities                |       | $                                                                                               | (445       | ) | $ | (74 | ) | $ | (1,737 | ) | $ | (543 | ) | $ | (1,938 | ) | $ | (2,088 | ) |
|                                                                                           |       |                                           |       |                                                                                            |       |   |   |   |   |   |   |   |   |   |   |
| **Total  Electric Segment**                                                                    | ** ** | ** **                                     | ** ** | **$**                                                                                           | **(445**   | **)** | **$** | **(74** | **)** | **$** | **(1,737** | **)** | **$** | **(543** | **)** | **$** | **(1.938** | **)** | **$** | **(2,088** | **)** |

 
| **Derivatives Not  Designated as Hedging  Instruments - Due to** | ** ** | **Statement of  Operations  Classification of** | ** ** | **Amount of Gain / (Loss)  Recognized in Income on Derivatives** | ** ** |
|------------------------------------------------------------------------------------------------|------------|-----------------------------------------------------------|------------|------------------------------------------------------------------|------------|
| **Regulatory Accounting**                                                                 | ** ** | **Gain / (Loss) on**                       | ** ** | **Three Months Ended**                                 | ** ** | **Six Months Ended** | ** ** | **Twelve Months Ended** | ** ** |
| **Electric  Segment(1)**                                                             | ** ** | **Derivative**                                            | ** ** | **2010**                                                         | ** ** | **2009** | ** ** | **2010** | ** ** | **2009** | ** ** | **2010** | ** ** | **2009** | ** ** |
| Commodity contracts                                                                            |       | Fuel and purchased power expense                          |       | $                                                                | (135       | ) | $ | (30 | ) | $ | (397 | ) | $ | (678 | ) | $ | (1,521 | ) | $ | (1,007 | ) |
|                                                                                           |       |                                                      |       |                                                             |       |   |   |   |   |   |   |   |   |   |   |
| **Total  Electric Segment**                                                                    | ** ** | ** **                                                | ** ** | **$**                                                            | **(135**   | **)** | **$** | **(30** | **)** | **$** | **(397** | **)** | **$** | **(678** | **)** | **$** | **(1.521** | **)** | **$** | **(1,007** | **)** |

 

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**(1) **Allof our gas hedging activities are related to stabilizing fuel costs as part ofour fuel procurement program and are not speculative activities. If conditionschange, such as a planned unit outage, we may need to de-designate and/orunwind some of our previous derivatives. In this instance, these derivativeswould be classified into the category above.

 

We also enter into fixed-price forward physicalcontracts for the purchase of natural gas, coal and purchased power. Thesecontracts are not subject to fair value accounting because they are consideredto be normal purchases and are not derivatives. We have a process in place todetermine if any future executed contracts that otherwise qualify for thenormal purchase exception contain a price adjustment feature and will accountfor these contracts accordingly.

 

As of July 23, 2010, the following volumes andpercentage of our anticipated volume of natural gas usage for our electricoperations for the remainder of 2010 and for the next four years are shownbelow at the following average prices per Dekatherm (Dth).

 

**Dth Hedged**

 
| **Year**        | ** ** | **% Hedged** | ** ** | **Physical** | ** ** | **Financial** | ** ** | **Average Price** | ** ** |
|-----------------|------------|--------------|------------|--------------|------------|---------------|------------|-------------------|------------|
| Remainder  2010 |       | 80           | %          | 1,410,000    |       | 1,425,000     |       | $                 | 6.380      |   |
| 2011            |       | 75           | %          | 3,410,000    |       | 2,000,000     |       | $                 | 5.809      |   |
| 2012            |       | 40           | %          | 1,665,000    |       | 1,420,000     |       | $                 | 7.016      |   |
| 2013            |       | 25           | %          | 1,200,000    |       | 600,000       |       | $                 | 6.862      |   |
| 2014            |       | 8            | %          | —       |       | 620,000       |       | $                 | 6.115      |   |

 

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Weutilize the following procurement guidelines for our electric segment, subject to a maximum of 80% of the expectedgas usage in any one year (except for the current year):

 
| **Year** | ** ** | **Minimum % Hedged** | ** ** |
|----------|------------|--------------------------------|------------|
| Current  |       | Up to 100%                     |       |
| First    |       | 60%                            |       |
| Second   |       | 40%                            |       |
| Third    |       | 20%                            |       |
| Fourth   |       | 10%                            |       |

 

*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 June 30, 2010, we had 1.0 millionDths in storage on the three pipelines that serve our customers. Thisrepresents 52% of our storage capacity. We have an additional 0.4 million Dthshedged through financial derivative and physical contracts. Our long-term hedgestrategy is to mitigate price volatility for our customers by hedging a minimumof 50% of current year, up to 50% of second year and up to 20% of third yearexpected gas usage by the beginning of the Actual Cost Adjustment (ACA)year at September 1. A PurchasedGas Adjustment (PGA) clause is included in our rates for our gas segmentoperations, therefore, we mark to market any unrealized gains or losses and anyrealized gains or losses relating to financial derivative contracts to aregulatory asset or regulatory liability account on our balance sheet.

 

Thefollowing table sets forth “mark-to-market” pre-tax gains / (losses) fromderivatives not designated as hedging instruments for the gas segment for eachof the periods ended June 30, (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 / (Loss) on**            | ** ** | **Three Months Ended**                                                                | ** ** | **Six Months Ended** | ** ** | **Twelve Months Ended** | ** ** |
| **Segment**                                                                                 | ** ** | **Derivative**                                 | ** ** | **2010**                                                                                        | ** ** | **2009** | ** ** | **2010** | ** ** | **2009** | ** ** | **2010** | ** ** | **2009** | ** ** |
| Commodity contracts                                                                         |       | Regulatory  (assets)/liabilities               |       | $                                                                                               | (52        | ) | $ | 77 |   | $ | (121 | ) | $ | (1,761 | ) | $ | (142 | ) | $ | (8,210 | ) |
|                                                                                        |       |                                           |       |                                                                                            |       |   |   |   |   |   |   |   |   |   |   |
| **Total - Gas Segment**                                                                     | ** ** | ** **                                     | ** ** | **$**                                                                                           | **(52**    | **)** | **$** | **77** | ** ** | **$** | **(121** | **)** | **$** | **(1,761** | **)** | **$** | **(142** | **)** | **$** | **(8,210** | **)** |

 

*ContingentFeatures*

 

Certain of our derivative instruments containprovisions that require our senior unsecured debt to maintain an investmentgrade credit rating with any relevant credit rating agency. If our debt were tofall below investment grade, it would be in violation of these provisions, andthe counterparties to the derivative instruments could request increasedcollateralization on derivative instruments in net liability positions. Theaggregate fair value of all derivative instruments with the credit-risk-relatedcontingent features that are in a liability position on June 30, 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 June 30, 2010, we would have been required topost $1.2 million of collateral with the 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 

 

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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 3 fair value measurements consist of both quotedprice inputs and unobservable quoted inputs provided by a third party.

 

Theguidance also requires that the fair value measurement 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 June 30, 2010 and December 31, 2009.

 

**($ in 000’s)**

 
| ** **                         | ** ** | ** **                                        | ** ** | **Fair Value Measurements at Reporting Date Using**                   | ** ** |
|------------------------------------|------------|---------------------------------------------------|------------|-----------------------------------------------------------------------------------------------------|------------|
| **Description**                    | ** ** | **Assets/(Liabilities)  at Fair Value** | ** ** | **Quoted Prices in  Active Markets for  Identical Assets  (Level 1)** | ** ** | **Significant Other  Observable  Inputs  (Level 2)** | ** ** | **Significant  Unobservable  Inputs  (Level 3)** | ** ** |
| ** **                         | ** ** | **June 30, 2010**                            | ** ** |
| Commodity contracts (liabilities)* |       | $                                                 | (5,158     | )                                                                                                   | $          | (5,158 | ) | $ | — |   | $ | — |   |
|                               |       |                                              |       |                                                                                                |       |   |   |   |   |
|                               |       | **December 31, 2009**                        |       |
| Commodity contracts assets         |       | $                                                 | 544        |                                                                                                | $          | 544 |   | $ | — |   | $ | — |   |

 

----

*Theonly recurring measurements are derivative commodity contracts. 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 June 30,2010 and 2009:

 

**Fair Value Measurements Using Significant Unobservable Inputs (Level 3)— 3 Months Ended**

 
| ** **                                                                   | ** ** | **2010**                       | ** ** | **2009**                       | ** ** |
|------------------------------------------------------------------------------|------------|--------------------------------|------------|--------------------------------|------------|
| ** **                                                                   | ** ** | **Derivatives Commodity** | ** ** | **Derivatives Commodity** | ** ** |
| **($ in 000’s)**                                              | ** ** | **Contracts(1)**               | ** ** | **Contracts(1)**               | ** ** |
| Beginning Balance, April 1,                                             |       | $                              | —     |                           | $          | 3,752 |   |
| Total gains or (losses) (realized/unrealized)                                |       |                           |       |                           |       |
| Included in earnings (or changes in net assets)                              |       | —                         |       | —                         |       |
| Included in comprehensive income                                             |       |                           |       | 1,012                          |       |
| Purchases, issuances, and settlements                                        |       | —                         |       | —                         |       |
| Transfers into and (out of) Level 3(2) (3)                              |       |                           |       | (1,232                         | )          |
| Ending Balance, June 30,                                                |       | $                              | —     |                           | $          | 3,532 |   |
| Changes in unrealized gains relating to assets  still held at reporting date |       | $                              | —     |                           | $          | 1,012 |   |

 

----

(1) Netcommodity contracts at June 30, 2010 and 2009 included $0.0 million and$3.5 million, 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.

 

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**Fair Value Measurements Using Significant Unobservable Inputs (Level 3)— 6 Months Ended**

 
| ** **                                                                   | ** ** | **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                                             |       |                           |       | (1,444                         | )          |
| Purchases, issuances, and settlements                                        |       | —                         |       | —                         |       |
| Transfers into and (out of) Level 3(2) (3)                              |       |                           |       | (1,232                         | )          |
| Ending Balance, June 30,                                                |       | $                              | —     |                           | $          | 3,532 |   |
| Changes in unrealized gains relating to assets  still held at reporting date |       | $                              | —     |                           | $          | (1,444 | ) |

 

----

(1) Netcommodity contracts at June 30, 2010 and 2009 included $0.0 million and$3.5 million, respectively, in derivative assets, and no derivativeliabilities.

(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.

 

**Fair Value Measurements Using Significant Unobservable Inputs (Level 3)— 12 Months Ended**

 
| ** **                                                                   | ** ** | **2010**                       | ** ** | **2009**                       | ** ** |
|------------------------------------------------------------------------------|------------|--------------------------------|------------|--------------------------------|------------|
| ** **                                                                   | ** ** | **Derivatives Commodity** | ** ** | **Derivatives Commodity** | ** ** |
| **($ in 000’s)**                                              | ** ** | **Contracts(1)**               | ** ** | **Contracts(1)**               | ** ** |
| Beginning Balance, July 1,                                              |       | $                              | 3,532      |                           | $          | 22,073 |   |
| Total gains or (losses) (realized/unrealized)                                |       |                           |       |                           |       |
| Included in earnings (or changes in net assets)                              |       | —                         |       | —                         |       |
| Included in comprehensive income                                             |       | (295                           | )          | (17,309                        | )          |
| Purchases, issuances, and settlements                                        |       | —                         |       | —                         |       |
| Transfers into and (out of) Level 3(2) (3)                              |       | (3,237                         | )          | (1,232                         | )          |
| Ending Balance, June 30,                                                |       | $                              | —     |                           | $          | 3,532 |   |
| Changes in unrealized gains relating to assets  still held at reporting date |       | $                              | (295       | )                              | $          | (17,309 | ) |

 

----

(1) Netcommodity contracts at June 30, 2010 and 2009 included $0.0 million and$3.5 million, respectively, in derivative assets, and no derivativeliabilities.

(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 June 30,2010, was $687.5 million compared to a fair market value of approximately$716.3 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 June 30, 2010 or thatwill be realizable in the future.

 

**Note 6— Financing**

 

OnJuly 26, 2010, we issued a notice to call all $48.3 million aggregateprincipal amount of our Senior Notes, 7.05% Series due 2022 for redemptionon August 27, 2010. We expect to finance the redemption with an offeringof first mortgage bonds. The redemption is conditioned upon the consummation ofthis offering. If we are unable to complete this offering, the notice ofredemption would be of no effect unless we waive this condition.

 

OnMay 28, 2010, we issued $100 million principal amount of 4.65% firstmortgage bonds due June 1, 2020. The net proceeds (after payment ofexpenses) of approximately $98.9million were used to redeem all 2 million outstanding shares of our 8.5%trust preferred securities totaling 

 

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$50million, on June 28, 2010 and to repay short-term debt which was incurred,in part, to fund the repayment, at maturity, of our 6.5% first mortgage bondsdue 2010.

 

OnFebruary 25, 2009, we entered into an equity distribution agreement withUBS Securities LLC (UBS). Under the terms of the agreement, as amended, wecould offer and sell shares of our common stock, par value $1.00 per share,having an aggregate offering amount of up to $120 million from time to timethrough UBS, as sales agent. We successfully completed this equity distributionprogram during the second quarter of 2010 and used the net proceeds to repayshort-term debt and for general corporate purposes, including the funding ofour current construction program. During the second quarter of 2010, we issuedand sold 1,192,644 shares of our common stock pursuant to this equitydistribution program, at an average price per share of $18.60, resulting in netproceeds to us of approximately $21.5 million (after payment of approximately$0.7 million in commissions to the sales agent). Since inception of theprogram, in the aggregate, we issued and sold 6,535,216 shares pursuant to theprogram, at an average price per share of $18.36, resulting in net proceeds tous of approximately $116.0 million. Sales of the shares pursuant to the equitydistribution agreement were made at market prices or as otherwise agreed withUBS.

 

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 reduced over a fouryear period in line with the amount of construction expenditures we owed forPlum Point Unit 1 and terminated on July 15, 2010.

 

OnJanuary 26, 2010, we entered into the Second Amended and RestatedUnsecured Credit Agreement which amended and restated this facility again. Thisagreement extends 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 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 therevolving commitments remained unchanged at $150 million and there were noother material changes to the terms of the facility. The facility is used forworking capital, general corporate purposes and to back-up our use ofcommercial paper. This facility requires our total indebtedness to be less than62.5% of our total capitalization at the end of each fiscal quarter and ourEBITDA (defined as net income plus interest, taxes, depreciation andamortization) to be at least two times our interest charges 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 June 30, 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 were no outstandingborrowings under this agreement at June 30, 2010. However, $40.0 millionwas used to back up our outstanding commercial paper.

 

**Note 7— Commitments and Contingencies**

 

Weare a party to various claims and legal proceedings arising out of the normalcourse of our business. Management regularly analyzes this information, and hasprovided accruals for any 

 

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liabilities,in accordance with the guidelines presented in the ASC on accounting forcontingencies. In the opinion of management, it is not probable, given thecompany’s defenses, that the ultimate outcome of these claims and lawsuits willhave a material adverse effect upon our financial condition, or results ofoperations or cash flows.

 

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 lawsuit.

 

**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):

 

Firmphysical gas and transportation contracts

 
| July 1, 2010 through December 31, 2010     |   | $    | 27.5   |   |
|------------------------------------------------------|--------|------|--------|--------|
| January 1, 2011 through December 31,  2012 |   | 63.3 |   |
| 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 minimum requirementsof fuel under the contracts. We entered into a contract in the second quarterof 2010 to transport coal beginning June 30, 2010, which replaced acontract that expired June 29, 2010. The contract term is for six andone-half years and the minimum payments total approximately $91.9 million. Theminimum requirements for our coal and coal transportation contracts are asfollows (in millions):

 

Coaland coal transportation contracts

 
| July 1, 2010 through December 31, 2010     |   | $    | 16.3   |   |
|------------------------------------------------------|--------|------|--------|--------|
| 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.

 

Ourlong-term contract with Westar Energy for the purchase of capacity and energyexpired on May 31, 2010.

 

Wehave a long-term (30 year) agreement for the purchase of capacity from the PlumPoint Energy Station, a new 665-megawatt, coal-fired generating facility whichis being built by Dynegy near Osceola, Arkansas. Construction began in thespring of 2006 and the target date to meet in-service criteria is August 15,2010. We have the option to purchase an undivided ownership interest in the 50megawatts covered by the purchased power agreement in 2015. Commitments underthis contract total approximately $48.0 million through August 30, 2015.

 

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Wehave a 20-year purchased power agreement which began on December 15, 2008with Cloud County Windfarm, LLC, owned by Horizon Wind Energy, Houston, Texasto purchase the energy generated at the approximately 105-megawatt Phase 1Meridian Way Wind Farm located in Cloud County, Kansas which commencedcommercial operation on December 15, 2008. We also have a 20-year contractwith Elk River Windfarm, LLC, owned by IBERDROLA RENEWABLES, Inc.(formerly known as PPM Energy), to purchase the energy generated at the150-megawatt Elk River Windfarm located in Butler County, Kansas. Althoughthese agreements are considered operating leases under Generally AcceptedAccounting Principles (GAAP), payments for these wind agreements are recordedas purchased power expenses, and, because of the contingent nature of these payments,are not included in our operating lease obligations.

 

**New Construction**

 

OnMarch 14, 2006, we entered into contracts to purchase a 50 megawatt,7.52%, undivided interest in the Plum Point Energy Station described above. Thetarget date to meet in-service criteria is August 15, 2010. The estimatedcost is approximately $88.0 million, excluding allowance for funds used duringconstruction (AFUDC). Our share of the Plum Point costs through June 30,2010 was $85.9 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 June 30, 2010 was $217.8 million.

 

*Recoveryof construction costs*

 

Wefiled a rate increase request with the Missouri Public Service Commission(MPSC) on October 29, 2009 for an annual increase in base rates for ourMissouri electric customers in the amount of $68.2 million, or 19.6%. Thisrequest was primarily designed to allow us to recover the costs associated withenvironmental upgrades at Iatan 1 and our investment in new generating units atIatan 2 and the Plum Point Generating Station. As a result of the delay in theIatan 2 project, however, we agreed to not seek a permanent increase in thecurrent rate case for any costs associated with the Iatan 2 unit with theexception of that portion of the Iatan common plant needed to operate Iatan 1.A stipulated agreement was filed on May 12, 2010, calling for an annual increaseof $46.8 million, provided the Plum Point Generating Station meets itsin-service criteria by August 15, 2010. Should the in-service criteria notbe met, a base rate increase of $33.1 million is stipulated. The new rates areto be effective September 10, 2010. Both scenarios include incrementaladditional regulatory amortization in the amount of $10 million that will berecorded as depreciation expense. We have also agreed to the use ofconstruction accounting for our Plum Point project such as we use for our Iatan1 and Iatan 2 projects. However, construction accounting for Plum Point willnot apply for up to 60 days between when Plum Point becomes fully operationaland used for service and the date tariffs in this rate case become effective.Construction accounting allows us to defer certain charges as regulatoryassets, including depreciation, operating expenses and carrying costs, relatedto operation of the facilities until the facilities are ultimately included inour rate base. As of the date of this filing, we believe that we have met allbut one Plum Point in-service criteria. The remaining test requires that theunit operate at or above 80% of its design load for a continuous 120 hourperiod with emission equipment operating effectively. Four hours of this testmust be above 95% load. We currently estimate that this test will begin on orbefore August 8, 2010. We anticipate filing a rate case at the conclusionof this case to recover the Iatan 2 costs and Plum Point costs if necessary.

 

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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 wasprimarily to allow us to recover capital expenditures associated with ourinvestment in new generating units at Iatan 2 and the Plum Point Generating Station,environmental upgrades at Iatan 1 completed in 2009 and at our Asbury plantcompleted in 2008, and our Riverton 12 unit that went on line in 2007. Astipulated agreement was filed on May 4, 2010, and approved by the KCC on June 25,2010, calling for a $2.8 million, or 12.4%, increase in base rates effective July 1,2010. We will defer depreciation and operating and maintenance expense on bothPlum Point and Iatan 2 from their respective in-service dates until theeffective date for rates from the next Kansas case, expected to be anabbreviated rate case that will be filed within the next year. These deferralswill be recovered over a 3-5 year period as determined in that next case. Wewill record AFUDC on all Plum Point and Iatan 2 capital expenditures incurredafter January 31, 2010.

 

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 Oklahoma revenuesof approximately $3 million, or approximately 33%.

 

Thereare risks that actual costs may exceed budget estimates, delays may occur inobtaining permits and materials, suppliers and contractors may not perform asrequired under their contracts, there may be inadequate availability,productivity or increased cost of qualified craft labor, start-up activitiesmay take longer than currently planned, the scope and timing of projects maychange, the re-baselined schedule may not be met and other events beyond ourcontrol, including the failure of one or more of the generation plant co-ownersto pay their share of construction, operations and maintenance costs, may occurthat may materially affect the schedule, budget, cost and performance of theseprojects. In addition, costs will be subject to prudency reviews by ourregulators.

 

**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 one unit train 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 toaccurately estimate compliance costs for any new requirements, we expect themto be material, although recoverable in 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 thefuture they are also likely to include limits on emissions of mercury, otherhazardous air pollutants (HAPs) and so-called greenhouse gases (GHG) such ascarbon dioxide (CO2) and methane.

 

*Permits*

 

Underthe CAA we have obtained site operating permits, which are valid for fiveyears, for each of our plants. We received renewed permits for the Asbury,State Line and Energy Center plants in July 2010.

 

ThePrevention of Significant Deterioration (PSD) provisions of the CAA require apermit, and if necessary installation of pollution control equipment, whenmaking a major modification or a change in operation if such modification orchange is likely to cause a significant net increase in regulated emissions. InMay 2008, KCPL received a Federal grand jury subpoena under the CAArequesting documents relating to capital projects at Iatan 1. We own 12% ofIatan 1. We were informed by KCPL in September 2009 that the US Departmentof Justice does not intend to bring charges under the CAA in connection withrepair work, maintenance or modifications at Iatan Unit 1.

 

*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 haveemission allowances equal to the number of tons of SO2 emitted during a given year by each of theiraffected units. Allowances in excess of the annual emissions are banked forfuture 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 ($115 million in 2010 dollars) and absent otherregulatory requirements, it will likely be more economical for us to purchaseSO2 allowances than to build a scrubber at theAsbury Plant. If we were to purchase SO2 allowances,we would expect their cost to be fully recoverable in our rates.

 

*NO*x* Emissions*

 

TheCAA regulates the amount of NOx an affectedunit can emit. Each of our affected units is in compliance with the NOx limits applicable to it as currently operated.

 

Ozone,also called ground level smog, is formed by the mixing of NOx and Volatile Organic Compounds in the presenceof sunlight. On January 6, 2010, the EPA proposed to lower the primaryNational Ambient Air Quality Standard (NAAQS) for ozone designed to protectpublic health and to set a secondary NAAQS for ozone designed to protectsensitive vegetation and ecosystems. The EPA intends to issue final standardsby August 31, 2010. Once final standards are set, states will be requiredto develop State Implementation Plans (SIPs) which reflect these standards.

 

*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 UnitsNo. 1 and No. 2

 

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arelocated and Arkansas where the Plum Point Energy Station is located. Kansas wasnot included in CAIR and our Riverton Plant was 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.

 

TheCAIR requires covered states (including Missouri and Arkansas) to develop SIPsto comply with specific NOx and 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 forfuture 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 SO2 allowance usage projections, we expect toexhaust our banked allowances by mid-2011 and, as discussed above, will need topurchase additional SO2 allowances or build a scrubber at our AsburyPlant.

 

Inorder to meet CAIR requirements, a Selective Catalytic Reduction system (SCR),FGD scrubber system and baghouse were installed at our Iatan 1 plant and an SCRwas installed at our Asbury plant in 2008.

 

OnJuly 6, 2010, the EPA published a proposed CAIR replacement rule entitledthe Clean Air Transport Rule (CATR). As proposed, the CATR would includeKansas under the annual and ozone season NOx and the SO2 programs. Missouri would be dropped from theozone season NOx program whileArkansas would remain in the ozone season NOx program. The beginning date of regulation forthe proposed CATR is 2012. The final CATR is expected to be issued by the EPAwithin 12-14 months. The proposed rule requires a 71% reduction in SO2 from 2005 levels by 2014. Wedo not expect significant impacts on our operations because of new NOx requirements in CATR. Wecannot accurately estimate the cost of any final regulation or predict itsprecise timing and its impact on our operations at this time. However, absentsignificant changes to the proposed rule, we expect the final CATR toultimately require a scrubber and baghouse to be added to our Asbury facilityat an estimated cost of $115 million in 2010 dollars and may force retirementof our Riverton coal-fired assets or conversion to natural gas.

 

*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.

 

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 HAPs, including mercury, 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 to development of regulations under Section 112(r) ofthe CAA maximum achievable emission standards for the control of the emissionof HAPs, including mercury. The EPA is under a court order to issue a proposedEGU MACT regulation by March 16, 2011 and to finalize that regulation by November 16,2011. Absent a successful legal challenge, we expect EGU MACT regulation toultimately require a scrubber and baghouse to be added to our Asbury facilityat an estimated cost of $115 million in 2010 dollars and may force retirementof our Riverton coal-fired assets or conversion to natural gas.

 

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*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 our GHG emissions as required to the EPA in 2011 for EDE.Submission for EDG has been delayed until 2012.

 

On December 7, 2009,responding to a 2007 US Supreme Court decision that determined that GHGsconstitute “air pollutants” under the CAA, the EPA issued its final findingthat GHGs threaten both the public health and the public welfare. This “endangerment”finding does not itself trigger any EPA regulations, but is a necessarypredicate for the EPA to proceed with regulations to control GHGs. On May 13,2010, the EPA issued under the CAA its final Prevention of SignificantDeterioration and Title V Greenhouse Gas Tailoring Rule to address GHGemissions from stationary sources. The rule, which will be implemented in foursteps commencing January 2, 2011, and initially focus on large sources,sets thresholds for GHG emissions that determine when permits will be requiredunder the New Source Review Prevention of Significant Deterioration (PSD) andtitle V Operating Permit programs applicable to new and existing power plantsand other sources. Under the PSD program, required controls for GHG emissions wouldbe determined based on Best Available Control Technology (BACT) for which EPAintends to develop a guidance policy. Several parties have filed petitions withthe EPA and lawsuits challenging the EPA’s Endangerment Finding and theTailoring Rule.

 

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 federal regulations. Forexample, 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 submit sampling and summary reports to the Kansas Department ofHealth 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 theregulations and is expected to revise and re-propose the

 

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regulationsby October 2010. Under the initial regulations, we did not expect costsassociated with compliance to be material. We will reassess costs after theproposed revised rules are published.

 

*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 stateswould incorporate the new standards into wastewater discharge permits,including permits for coal ash ponds. We do not have sufficient informationregarding the future wastewater effluent discharge guidelines at this time toestimate additional costs that any new standards would impose on ouroperations. In April and May 2009, we received Information CollectionRequests from the EPA regarding our ash ponds, and have responded to suchrequests. All of the ash ponds are compliant with existing state and federalregulations.

 

OnJune 21, 2010, the EPA published in the Federal Register, its proposed newregulation pursuant to the Federal Resource Conservation and Recovery Act(RCRA) governing the management and storage of Coal Combustion Residuals (CCR).In the proposal the EPA presents two options: (1) regulation of CCR underRCRA subtitle C as a hazardous waste and (2) regulation of CCR under RCRAsubtitle D as a non-hazardous waste. We are currently performing a study toreview all ash management options and associated costs but have not developedspecific cost estimates to date. The EPA will accept comments until September 20,2010. It is anticipated that the final regulation will be published later thisyear or early in 2011. We expect compliance with the final version of eitherproposal to result in the need to construct a new landfill and the conversionof existing ash handling from a wet to a dry system(s). We have developed a workingpreliminary estimated cost of $18 million to comply with either proposal orcombination. We expect these costs to be recoverable in our rates. This is aworking estimate and we expect the total will change during the study process.

 

***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. In July 2010,the MPSC submitted to the Missouri secretary of state’s office its rule forthe renewable energy mandate. We are awaiting action from the Missourisecretary of state but believe we are in compliance with the law. Kansas establisheda renewable portfolio standard (RPS) in May 2009. Its final rulemaking isexpected to be released some time in August 2010. In addition, there areseveral proposals currently before the U.S. Congress to adopt a nationwide 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 cannotclaim the underlying energy is renewable. Once a REC has been claimed orretired, it cannot be used for any other purpose. Over time, we expect toretain a sufficient amount of RECs to meet any current or future RPS.

 

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***Gas Segment***

 

Theacquisition of our natural gas distribution assets in June 2006 involvedthe potential future remediation of two former manufactured gas plant (FMGP)sites. FMGP 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.

 

**Note 8 — Retirement Benefits**

 

Net periodic benefit pension cost, some of which is capitalized as acomponent of labor cost and some of which is deferred as a regulatory asset, iscomprised of the following components and is shown for our noncontributorydefined benefit pension plan, our supplemental retirement program (SERP) andother postretirement benefits (OPEB) (in thousands):

 
| ** **                                 | ** ** | **Three months ended June 30,** | ** ** |
|--------------------------------------------|------------|-----------------------------------------------------|------------|
| ** **                                 | ** ** | **Pension Benefits**                           | ** ** | **SERP** | ** ** | **OPEB** | ** ** |
| ** **                                 | ** ** | **2010**                                            | ** ** | **2009** | ** ** | **2010** | ** ** | **2009** | ** ** | **2010** | ** ** | **2009** | ** ** |
| Service cost                               |       | $                                                   | 1,273      |   | $ | 1,019 |   | $ | 17 |   | $ | 15 |   | $ | 509 |   | $ | 509 |   |
| Interest cost                              |       | 2,550                                               |       | 2,491 |   | 39 |   | 37 |   | 1,063 |   | 1,066 |   |
| Expected return on plan assets             |       | (2,483                                              | )          | (2,601 | ) | — |   | — |   | (966 | ) | (970 | ) |
| Amortization of prior service cost **(1)** |       | 133                                                 |       | 151 |   | (2 | ) | (2 | ) | (253 | ) | (253 | ) |
| Amortization of net actuarial loss **(1)** |       | 1,033                                               |       | 837 |   | 32 |   | 20 |   | 344 |   | 356 |   |
| **Net periodic benefit cost**              | ** ** | **$**                                               | **2,506**  | ** ** | **$** | **1,897** | ** ** | **$** | **86** | ** ** | **$** | **70** | ** ** | **$** | **697** | ** ** | **$** | **708** | ** ** |

 
| ** **                                 | ** ** | **Six months ended June 30,** | ** ** |
|--------------------------------------------|------------|------------------------------------|------------|
| ** **                                 | ** ** | **Pension Benefits**               | ** ** | **SERP** | ** ** | **OPEB** | ** ** |
| ** **                                 | ** ** | **2010**                           | ** ** | **2009** | ** ** | **2010** | ** ** | **2009** | ** ** | **2010** | ** ** | **2009** | ** ** |
| Service cost                               |       | $                                  | 2,546      |   | $ | 2,010 |   | $ | 34 |   | $ | 31 |   | $ | 1,018 |   | $ | 963 |   |
| Interest cost                              |       | 5,100                              |       | 4,929 |   | 79 |   | 74 |   | 2,125 |   | 2,051 |   |
| Expected return on plan assets             |       | (4,966                             | )          | (5,202 | ) | — |   | — |   | (1,933 | ) | (1,930 | ) |
| Amortization of prior service cost **(1)** |       | 266                                |       | 302 |   | (4 | ) | (4 | ) | (506 | ) | (505 | ) |
| Amortization of net actuarial loss **(1)** |       | 2,067                              |       | 1,591 |   | 63 |   | 51 |   | 689 |   | 588 |   |
| **Net periodic benefit cost**              | ** ** | **$**                              | **5,013**  | ** ** | **$** | **3,630** | ** ** | **$** | **172** | ** ** | **$** | **152** | ** ** | **$** | **1,393** | ** ** | **$** | **1,167** | ** ** |

 
| ** **                                 | ** ** | **Twelve months ended June 30,** | ** ** |
|--------------------------------------------|------------|---------------------------------------|------------|
| ** **                                 | ** ** | **Pension Benefits**                  | ** ** | **SERP** | ** ** | **OPEB** | ** ** |
| ** **                                 | ** ** | **2010**                              | ** ** | **2009** | ** ** | **2010** | ** ** | **2009** | ** ** | **2010** | ** ** | **2009** | ** ** |
| Service cost                               |       | $                                     | 5,148      |   | $ | 3,853 |   | $ | 65 |   | $ | 64 |   | $ | 1,885 |   | $ | 1,800 |   |
| Interest cost                              |       | 10,047                                |       | 9,486 |   | 152 |   | 147 |   | 3,980 |   | 3,848 |   |
| Expected return on plan assets             |       | (10,143                               | )          | (10,573 | ) | — |   | — |   | (3,845 | ) | (3,804 | ) |
| Amortization of prior service cost **(1)** |       | 568                                   |       | 674 |   | (8 | ) | (8 | ) | (1,011 | ) | (1,011 | ) |
| Amortization of net actuarial loss **(1)** |       | 3,658                                 |       | 2,477 |   | 115 |   | 123 |   | 970 |   | 820 |   |
| **Net periodic benefit cost**              | ** ** | **$**                                 | **9,278**  | ** ** | **$** | **5,917** | ** ** | **$** | **324** | ** ** | **$** | **326** | ** ** | **$** | **1,979** | ** ** | **$** | **1,653** | ** ** |

 

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(1) Amounts are amortized from our regulatory asset originallyrecorded upon adoption of FAS 158.

 

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 in accordance with our minimum regulatory agreements.We estimate our 2010 funding to be approximately $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 fund approximately $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.

 

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**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 June 30(in thousands):

 
| ** **                 | ** ** | **Three Months Ended** | ** ** | **Six Months Ended** | ** ** | **Twelve Months Ended** | ** ** |
|----------------------------|------------|------------------------|------------|----------------------|------------|-------------------------|------------|
| ** **                 | ** ** | **2010**               | ** ** | **2009**             | ** ** | **2010**                | ** ** | **2009** | ** ** | **2010** | ** ** | **2009** | ** ** |
| **Compensation Expense**   |       | $                      | 730        |                 | $          | 669                     |       | $ | 1,528 |   | $ | 1,248 |   | $ | 2,572 |   | $ | 1,712 |   |
| **Tax Benefit Recognized** |       | 261                    |       | 244                  |       | 549                     |       | 453 |   | 915 |   | 607 |   |
|                            |            |                        |            |                      |            |                         |            |  |  |  |  |  |  |  |  |  |  |  |  |

 

Activityfor our various stock plans for the six months ended June 30, 2010 is summarizedbelow:

 

**Performance-BasedRestricted Stock Awards**

 

Performance-basedrestricted stock awards are granted to qualified individuals consisting of theright to receive a number of shares of common stock at the end of therestricted period assuming performance criteria are met. The fair value of theoutstanding restricted stock awards was estimated using a Monte Carlo optionvaluation model. The assumptions used in the model for each grant year arenoted in the following table:

 
| ** **                                   | ** ** | **Fair Value of Grants Outstanding at June 30,** | ** ** |
|----------------------------------------------|------------|-------------------------------------------------------|------------|
| ** **                                   | ** ** | **2010**                                              | ** ** | **2009** | ** ** |
| **Risk-free interest rate**                  |       | 0.22% to 0.80%                                        |       | 0.35% to 1.37% |   |
| **Expected volatility of Empire  stock**     |       | 28.6%                                                 |       | 28.8% |   |
| **Expected volatility of peer  group stock** |       | 22.4% to 83.0%                                        |       | 21.8% to 79.6% |   |
| **Expected dividend yield on Empire  stock** |       | 7.0%                                                  |       | 7.3% |   |
| **Expected forfeiture rates**                |       | 3%                                                    |       | 3% |   |
| **Plan cycle**                               |       | 3 years                                               |       | 3 years |   |
| **Fair value percentage**                    |       | 124.0% to 152.0%                                      |       | 105.0% to 130.0% |   |
| **Weighted average fair value per  share**   |       | $26.21                                                |       | $19.29 |   |

 

Non-vestedrestricted stock awards (based on target number) as of June 30, 2010 and2009 and changes during the six months ended June 30, 2010 and 2009 wereas follows:

 
| ** **                       | ** ** | **2010**      | ** ** | **2009**             | ** ** |
|----------------------------------|------------|---------------|------------|----------------------|------------|
| ** **                       | ** ** | **Number**    | ** ** | **Weighted Average** | ** ** | **Number** | ** ** | **Weighted Average** | ** ** |
| ** **                       | ** ** | **of shares** | ** ** | **Grant Date Price** | ** ** | **of shares** | ** ** | **Grant Date Price** | ** ** |
| **Nonvested 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 June 30,**   |       | 47,500        |       | $                    | 19.86      |   | 52,200 |   | $ | 21.57 |   |

 

AtJune 30, 2010, there was $0.5 million of total unrecognized compensationcost related to estimated outstanding awards. This cost will be recognized overthe outstanding years remaining in the vesting period.

 

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**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 June 30,2010 and 2009, under a Black-Scholes methodology. The assumptions used in thevaluations are shown below:

 
| ** **                                  | ** ** | **Fair Value of Grants Outstanding at June 30,** | ** ** |
|---------------------------------------------|------------|-------------------------------------------------------|------------|
| ** **                                  | ** ** | **2010**                                              | ** ** | **2009** | ** ** |
| **Risk-free  interest rate**                |       | 0.55% to 2.23%                                        |       | 1.25% to 2.97% |   |
| **Dividend  yield**                         |       | 7.0%                                                  |       | 7.3% |   |
| **Expected  volatility**                    |       | 24.0%                                                 |       | 24.0% |   |
| **Expected  life in months**                |       | 78                                                    |       | 78 |   |
| **Market  value**                           |       | $ 18.77                                          |       | $ 16.52 |   |
| **Weighted  average fair value per option** |       | $   1.05                               |       | $   0.63 |   |

 

Asummary of option activity under the plan during the six months ended June 30,2010 and 2009 is presented below:

 
| ** **                         | ** ** | **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 June 30,**   |       | 267,400     |       | $                    | 21.69      |   | 232,600 |   | $ | 22.19 |   |
| **Exercisable at June 30,**   |       | 149,200     |       | $                    | 23.04      |   | 85,000 |   | $ | 22.46 |   |

 

Theaggregate intrinsic value at June 30, 2010 was less than $0.1 million andat June 30, 2009 was zero. The intrinsic value of the unexercised optionsis the difference between Empire’s closing stock price on the last day of thequarter and the exercise price multiplied by the number of in the money optionshad all option holders exercised their option on the last day of the quarter.The intrinsic value is zero if such closing price is less than the exerciseprice.

 

Therange of exercise prices for the options outstanding at June 30, 2010 was$18.12 to $23.81. The weighted-average remaining contractual life ofoutstanding options at June 30, 2010 and 2009 was 7.1 years and 7.1 years,respectively. As of June 30, 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.

 

**EmployeeStock Purchase Plan**

 

OurEmployee Stock Purchase Plan (ESPP) permits the grant to eligible employees ofoptions to purchase common stock at 90% of the lower of market value at date ofgrant or at date of exercise. The lookback feature of this plan is valued at90% of the Black-Scholes methodology plus 10% of the maximum subscriptionprice. As of June 30, 2010, there were 331,021 shares available forissuance in this plan.

 
| ** **                                     | ** ** | **2010** | ** ** | **2009** | ** ** |
|------------------------------------------------|------------|----------|------------|----------|------------|
| **Subscriptions outstanding at  June 30** |       | 72,874   |       | 69,830   |       |
| **Maximum subscription price**                 |       | $        | 16.06      |     | $          | 14.62 |   |
| **Shares of stock issued**(1)                  |       | 66,723   |       | 44,265   |       |
| **Stock issuance price**                       |       | $        | 14.62      |     | $          | 14.10 |   |

 

----

(1) Stockwill be issued on the closing date of the purchase period, which runs from June 1,2010 to May 31, 2011.

 

Assumptionsfor valuation of these shares are shown in the table below.

 

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| ** **                                 | ** ** | **ESPP** | ** ** |
|--------------------------------------------|------------|----------|------------|
| ** **                                 | ** ** | **2010** | ** ** | **2009** | ** ** |
|                                       |       |     |       |   |   |
| **Weighted average fair value of  grants** |       | $        | 2.28       |   | $ | 3.26 |   |
| **Risk-free interest rate**                |       | 0.35     | %          | 0.48 | % |
| **Dividend yield**                         |       | 7.20     | %          | 7.90 | % |
| **Expected volatility**                    |       | 17.00    | %          | 40.00 | % |
| **Expected life in months**                |       | 12       |       | 12 |   |
| **Grant Date**                             |       | 6/1/10   |       | 6/1/09 |   |
|                                            |            |          |            |  |  |  |  |

 

**Note 10- Regulated Operating Expenses**

 

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 June 30:

 
| ** **                                        | ** ** | **Three  Months  Ended** | ** ** | **Three  Months  Ended** | ** ** | **Six  Months  Ended** | ** ** | **Six  Months  Ended** | ** ** | **Twelve  Months  Ended** | ** ** | **Twelve  Months  Ended** | ** ** |
|---------------------------------------------------|------------|--------------------------|------------|--------------------------|------------|------------------------|------------|------------------------|------------|---------------------------|------------|---------------------------|------------|
| ** **                                        | ** ** | **2010**                 | ** ** | **2009**                 | ** ** | **2010**               | ** ** | **2009**               | ** ** | **2010**                  | ** ** | **2009**                  | ** ** |
| Electric transmission and distribution expense    |       | $                        | 3,144      |                     | $          | 2,747                  |       | $                      | 5,971      |                      | $          | 5,337                     |       | $ | 11,697 |   | $ | 10,884 |   |
| Natural gas transmission and distribution expense |       | 515                      |       | 548                      |       | 1,046                  |       | 1,074                  |       | 2,133                     |       | 2,119                     |       |
| Power operation expense (other than fuel)         |       | 2,791                    |       | 3,062                    |       | 5,695                  |       | 6,126                  |       | 11,884                    |       | 12,369                    |       |
| Customer accounts and assistance expense          |       | 2,998                    |       | 2,736                    |       | 5,917                  |       | 5,187                  |       | 11,326                    |       | 10,366                    |       |
| Employee pension expense (1)                      |       | 1,287                    |       | 1,327                    |       | 2,751                  |       | 2,687                  |       | 5,622                     |       | 5,457                     |       |
| Employee healthcare plan (1)                      |       | 1,696                    |       | 1,375                    |       | 3,246                  |       | 2,691                  |       | 6,463                     |       | 5,941                     |       |
| General office supplies and expense               |       | 2,705                    |       | 2,564                    |       | 5,381                  |       | 4,824                  |       | 10,626                    |       | 9,312                     |       |
| Administrative and general expense                |       | 3,218                    |       | 2,851                    |       | 6,634                  |       | 5,850                  |       | 12,995                    |       | 12,090                    |       |
| Allowance for uncollectible accounts              |       | 855                      |       | 853                      |       | 1,455                  |       | 1,800                  |       | 2,780                     |       | 3,294                     |       |
| Miscellaneous expense                             |       | 63                       |       | 13                       |       | 93                     |       | 1                      |       | 172                       |       | 102                       |       |
| Total                                             |       | $                        | 19,272     |                     | $          | 18,076                 |       | $                      | 38,189     |                      | $          | 35,577                    |       | $ | 75,698 |   | $ | 71,934 |   |

 

----

(1) Does not include capitalized portion of costs, but reflectsthe GAAP 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**

 

Weoperate our business as three segments: electric, gas and other. As part of our electric segment, we alsoprovide water service to three towns in Missouri. The other segment consists ofour fiber optics business.

 

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

 
| ** **                               | ** ** | **For the quarter ended June 30, 2010** | ** ** |
|------------------------------------------|------------|----------------------------------------------|------------|
| **($-000’s)**                       | ** ** | **Electric**                                 | ** ** | **Gas** | ** ** | **Other** | ** ** | **Eliminations** | ** ** | **Total** | ** ** |
| **Statement of Operations  Information** |       |                                         |       |   |   |   |   |   |   |   |   |
| Revenues                                 |       | $                                            | 106,686    |   | $ | 6,516 |   | $ | 1,428 |   | $ | (148 | ) | $ | 114,482 |   |
| Depreciation and amortization            |       | 12,373                                       |       | 831 |   | 382 |   | — |   | 13,586 |   |
| Federal and state income taxes           |       | 4,497                                        |       | (219 | ) | 207 |   | — |   | 4,485 |   |
| Operating income                         |       | 13,388                                       |       | 543 |   | 348 |   | — |   | 14,279 |   |
| Interest income                          |       | 61                                           |       | 133 |   | — |   | (142 | ) | 52 |   |
| Interest expense                         |       | 10,147                                       |       | 986 |   | 12 |   | (142 | ) | 11,003 |   |
| Income from AFUDC (debt and equity)      |       | 4,337                                        |       | 6 |   | — |   | — |   | 4,343 |   |
| Net income                               |       | 7,405                                        |       | (372 | ) | 336 |   | — |   | 7,369 |   |
|                                     |       |                                         |       |   |   |   |   |   |   |   |   |
| **Capital Expenditures**                 |       | $                                            | 24,545     |   | $ | 598 |   | $ | 608 |   |   |   | $ | 25,751 |   |
|                                          |            |                                              |            |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

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| ** **                               | ** ** | **For the quarter ended June 30, 2009** | ** ** |
|------------------------------------------|------------|----------------------------------------------|------------|
| **($-000’s)**                       | ** ** | **Electric**                                 | ** ** | **Gas** | ** ** | **Other** | ** ** | **Eliminations** | ** ** | **Total** | ** ** |
| **Statement of Operations  Information** |       |                                         |       |   |   |   |   |   |   |   |   |
| Revenues                                 |       | $                                            | 103,083    |   | $ | 7,919 |   | $ | 1,376 |   | $ | (148 | ) | $ | 112,230 |   |
| Depreciation and amortization            |       | 11,888                                       |       | 503 |   | 348 |   | — |   | 12,739 |   |
| Federal and state income taxes           |       | 4,293                                        |       | (467 | ) | 221 |   | — |   | 4,047 |   |
| Operating income                         |       | 15,500                                       |       | 155 |   | 372 |   | — |   | 16,027 |   |
| Interest income                          |       | 61                                           |       | 108 |   | — |   | (108 | ) | 61 |   |
| Interest expense                         |       | 10,841                                       |       | 988 |   | 13 |   | (108 | ) | 11,734 |   |
| Income from AFUDC (debt and equity)      |       | 3,335                                        |       | — |   | — |   | — |   | 3,335 |   |
| Net income                               |       | 8,018                                        |       | (750 | ) | 359 |   | — |   | 7,627 |   |
|                                     |       |                                         |       |   |   |   |   |   |   |   |   |
| **Capital Expenditures**                 |       | $                                            | 40,673     |   | $ | 386 |   | $ | 246 |   |   |   | $ | 41,305 |   |
|                                          |            |                                              |            |  |  |  |  |  |  |  |  |  |  |  |  |  |

 
| ** **                               | ** ** | **For the six months ended June 30, 2010** | ** ** |
|------------------------------------------|------------|-------------------------------------------------|------------|
| **($-000’s)**                       | ** ** | **Electric**                                    | ** ** | **Gas** | ** ** | **Other** | ** ** | **Eliminations** | ** ** | **Total** | ** ** |
| **Statement of Operations  Information** |       |                                            |       |   |   |   |   |   |   |   |   |
| Revenues                                 |       | $                                               | 220,718    |   | $ | 31,077 |   | $ | 2,877 |   | $ | (296 | ) | $ | 254,376 |   |
| Depreciation and amortization            |       | 24,674                                          |       | 1,339 |   | 758 |   | — |   | 26,771 |   |
| Federal and state income taxes           |       | 12,778                                          |       | 1,220 |   | 421 |   | — |   | 14,419 |   |
| Operating income                         |       | 25,873                                          |       | 3,778 |   | 706 |   | — |   | 30,357 |   |
| Interest income                          |       | 133                                             |       | 259 |   | — |   | (270 | ) | 122 |   |
| Interest expense                         |       | 20,707                                          |       | 1,969 |   | 22 |   | (270 | ) | 22,428 |   |
| Income from AFUDC (debt and equity)      |       | 8,492                                           |       | 6 |   | — |   | — |   | 8,498 |   |
| Net income                               |       | 13,329                                          |       | 1,942 |   | 684 |   | — |   | 15,955 |   |
|                                     |       |                                            |       |   |   |   |   |   |   |   |   |
| **Capital Expenditures**                 |       | $                                               | 53,781     |   | $ | 886 |   | $ | 1,959 |   |   |   | $ | 56,626 |   |
|                                          |            |                                                 |            |  |  |  |  |  |  |  |  |  |  |  |  |  |

 
| ** **                               | ** ** | **For the six months ended June 30, 2009** | ** ** |
|------------------------------------------|------------|-------------------------------------------------|------------|
| **($-000’s)**                       | ** ** | **Electric**                                    | ** ** | **Gas** | ** ** | **Other** | ** ** | **Eliminations** | ** ** | **Total** | ** ** |
| **Statement of Operations  Information** |       |                                            |       |   |   |   |   |   |   |   |   |
| Revenues                                 |       | $                                               | 209,870    |   | $ | 36,006 |   | $ | 2,678 |   | $ | (309 | ) | $ | 248,245 |   |
| Depreciation and amortization            |       | 23,717                                          |       | 1,003 |   | 692 |   | — |   | 25,412 |   |
| Federal and state income taxes           |       | 8,663                                           |       | 576 |   | 416 |   | — |   | 9,655 |   |
| Operating income                         |       | 31,198                                          |       | 2,769 |   | 715 |   | — |   | 34,682 |   |
| Interest income                          |       | 136                                             |       | 266 |   | — |   | (265 | ) | 137 |   |
| Interest expense                         |       | 21,400                                          |       | 1,984 |   | 40 |   | (265 | ) | 23,159 |   |
| Income from AFUDC (debt and equity)      |       | 6,938                                           |       | 1 |   | — |   | — |   | 6,939 |   |
| Net income                               |       | 16,861                                          |       | 1,003 |   | 676 |   | — |   | 18,540 |   |
|                                     |       |                                            |       |   |   |   |   |   |   |   |   |
| **Capital Expenditures**                 |       | $                                               | 80,667     |   | $ | 855 |   | $ | 792 |   |   |   | $ | 82,314 |   |
|                                          |            |                                                 |            |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

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| ** **                               | ** ** | **For the twelve months ended June 30, 2010** | ** ** |
|------------------------------------------|------------|----------------------------------------------------|------------|
| **($-000’s)**                       | ** ** | **Electric**                                       | ** ** | **Gas** | ** ** | **Other** | ** ** | **Eliminations** | ** ** | **Total** | ** ** |
| **Statement of Operations  Information** |       |                                               |       |   |   |   |   |   |   |   |   |
| Revenues                                 |       | $                                                  | 445,745    |   | $ | 52,384 |   | $ | 5,762 |   | $ | (592 | ) | $ | 503,299 |   |
| Depreciation and amortization            |       | 48,992                                             |       | 2,352 |   | 1,509 |   | — |   | 52,853 |   |
| Federal and state income taxes           |       | 22,598                                             |       | 1,216 |   | 832 |   | — |   | 24,646 |   |
| Operating income                         |       | 63,089                                             |       | 5,643 |   | 1,438 |   | — |   | 70,170 |   |
| Interest income                          |       | 222                                                |       | 396 |   | — |   | (416 | ) | 202 |   |
| Interest expense                         |       | 42,481                                             |       | 3,943 |   | 39 |   | (416 | ) | 46,047 |   |
| Income from AFUDC (debt and equity)      |       | 15,684                                             |       | 7 |   | — |   | — |   | 15,691 |   |
| Net income                               |       | 35,546                                             |       | 1,813 |   | 1,352 |   | — |   | 38,711 |   |
|                                     |       |                                               |       |   |   |   |   |   |   |   |   |
| **Capital Expenditures**                 |       | $                                                  | 126,589    |   | $ | 2,287 |   | $ | 2,430 |   |   |   | $ | 131,306 |   |
|                                          |            |                                                    |            |  |  |  |  |  |  |  |  |  |  |  |  |  |

 
| ** **                               | ** ** | **For the twelve months ended June 30, 2009** | ** ** |
|------------------------------------------|------------|----------------------------------------------------|------------|
| **($-000’s)**                       | ** ** | **Electric**                                       | ** ** | **Gas** | ** ** | **Other** | ** ** | **Eliminations** | ** ** | **Total** | ** ** |
| **Statement of Operations  Information** |       |                                               |       |   |   |   |   |   |   |   |   |
| Revenues                                 |       | $                                                  | 448,435    |   | $ | 65,020 |   | $ | 5,300 |   | $ | (573 | ) | $ | 518,182 |   |
| Depreciation and amortization            |       | 48,149                                             |       | 1,982 |   | 1,360 |   | — |   | 51,491 |   |
| Federal and state income taxes           |       | 22,472                                             |       | 457 |   | 493 |   | — |   | 23,422 |   |
| Operating income                         |       | 72,965                                             |       | 4,550 |   | 1,294 |   | — |   | 78,809 |   |
| Interest income                          |       | 642                                                |       | 393 |   | — |   | (463 | ) | 572 |   |
| Interest expense                         |       | 42,369                                             |       | 3,965 |   | 139 |   | (463 | ) | 46,010 |   |
| Income from AFUDC (debt and equity)      |       | 13,970                                             |       | 9 |   | — |   | — |   | 13,979 |   |
| Net Income                               |       | 44,781                                             |       | 873 |   | 801 |   | — |   | 46,455 |   |
|                                     |       |                                               |       |   |   |   |   |   |   |   |   |
| **Capital Expenditures**                 |       | $                                                  | 180,202    |   | $ | 2,105 |   | $ | 1,665 |   |   |   | $ | 183,972 |   |
|                                          |            |                                                    |            |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

**As of June 30, 2010**

 
| **($-000’s)**            | ** ** | **Electric** | ** ** | **Gas(1)** | ** ** | **Other** | ** ** | **Eliminations** | ** ** | **Total** | ** ** |
|-------------------------------|------------|--------------|------------|------------|------------|-----------|------------|------------------|------------|-----------|------------|
| **Balance Sheet Information** |       |         |       |       |       |      |       |             |       |      |       |
| Total assets                  |       | $            | 1,797,172  |       | $          | 135,986   |       | $                | 23,085     |      | $          | (86,550 | ) | $ | 1,869,693 |   |
|                               |            |              |            |            |            |           |            |                  |            |           |            |  |  |  |  |  |

 

----

(1) Includes goodwill 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) Includes goodwill of $39,492.

 

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**Note 12—Income Taxes**

 

Thefollowing table shows our consolidated effective federal and state income taxrates for the applicable periods ended June 30, 2010:

 
| ** **                                                 | ** ** | **Three Months Ended** | ** ** | **Six-Months Ended** | ** ** | **Twelve Months Ended** | ** ** |
|------------------------------------------------------------|------------|------------------------|------------|----------------------|------------|-------------------------|------------|
| ** **                                                 | ** ** | **2010**               | ** ** | **2009**             | ** ** | **2010**                | ** ** | **2009** | ** ** | **2010** | ** ** | **2009** | ** ** |
| Consolidated effective federal and state income  tax rates |       | 37.7%                  |       | 34.7%                |       | 47.5%                   |       | 34.2% |   | 38.9% |   | 33.5% |   |

 

The effective tax rates for the six months ended June 30, 2010 andthe twelve months ended June 30, 2010 are higher than comparable yearperiods primarily due to the new health care legislation. On March 23,2010, the Patient Protection and Affordable Care Act became law. Thislegislation includes a provision that reduces the deductibility, for income taxpurposes, of retiree healthcare costs to the extent an employer receivesfederal subsidies. Companies receive the subsidy when they provide retireeprescription benefits at least equivalent to Medicare Part D coverage intheir postretirement healthcare plan. Although the elimination of this taxbenefit does not take effect until 2013, this change requires us to recognizethe full accounting impact in our financial statements in the period in whichthe legislation is enacted. As a result, in the first quarter of 2010, werecorded a one-time non-cash charge of approximately $2.1 million to incometaxes to reflect the impact of this change. The change in deductibility willincrease our effective tax rate slightly during the remainder of 2010. Our 2010effective tax rate also increased due to the additional tax expense associatedwith the current year retiree health 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 in the first quarter of 2010. Amortization of the remaining regulatorytax asset will begin in 2012, which is also when we expect to be able torequest rate recovery of the asset.

 

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 June 30, 2010.

 

**Item 2.  Management’sDiscussion and Analysis of Financial Condition and Results of Operations**

 

**EXECUTIVE SUMMARY**

 

We operate our businesses as three segments: electric, gas and other.The****Empire District Electric Company (EDE)is an operating public utility engaged in the generation, purchase,transmission, distribution and sale of electricity in parts of Missouri,Kansas, Oklahoma and Arkansas. As part of our electric segment, we also 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 June 30 2010, 88.6% of our gross operating revenueswere provided from sales from our electric segment (including 0.4% from thesale of water), 10.4% from our gas segment and 1.0% from our other segment.

 

***Earnings***

 

Duringthe second quarter of 2010, basic and diluted earnings per weighted averageshare of common stock were $0.18 as compared to $0.22 in the second quarter of2009. For the six

 

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monthsended June 30, 2010, basic and diluted earnings per weighted average shareof common stock were $0.40 as compared to $0.54 for the six months ended June 30,2009. For the twelve months ended June 30, 2010, basic earnings perweighted average share of common stock were $1.03 as compared to $1.37 for thetwelve months ended June 30, 2009 and diluted earnings per weightedaverage share of common stock were $1.03 as compared to $1.36 for the twelvemonths ended June 30, 2009. The primary negative drivers for all threeperiods presented were increased electric operations and maintenance expensesand the dilutive effect of additional shares of common stock issued. Alsonegatively impacting both the six months and twelve months ended June 30, 2010 were the two non-cash charges inthe first quarter of 2010 discussed below. The primary positive driver for boththe second quarter of 2010 and the six months ended June 30, 2010 wasincreased electric revenues resulting from increased demand in the both thefirst and second quarters of 2010 resulting from favorable weather. IncreasedAFUDC favorably impacted all three periods presented.

 

Thetable below sets forth a reconciliation of basic and diluted earnings per sharebetween the three months, six months and twelve months ended June 30, 2009and June 30, 2010, which is a non-GAAP presentation. The economicsubstance behind our non-GAAP earning per share (EPS) measure is to present theafter tax impact of significant items and components of the statement of incomeon a per share basis before the impact of additional stock issuances.

 

Webelieve this presentation is useful to investors because the statement ofincome does not readily show the 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 change from the previous year’s EPS. Thisinformation is useful to management, and we believe this information is usefulto investors, to better understand the reasons for the fluctuation in EPSbetween the prior and current years on a per share basis.

 

Thisreconciliation may not be comparable to other companies or more useful than theGAAP presentation included in the statement of income. We also note that thispresentation does not purport to be an alternative to earnings per sharedetermined in accordance with GAAP as a measure of operating performance or anyother measure of financial performance presented in accordance with GAAP.Management compensates for the limitations of using non-GAAP financial measuresby using them to supplement GAAP results to provide a more completeunderstanding of the factors and trends affecting the business than GAAPresults alone.

 
| ** **                                        | ** ** | **Three Months  Ended** | ** ** | **Six Months  Ended** | ** ** | **Twelve Months  Ended** | ** ** |
|---------------------------------------------------|------------|-------------------------|------------|-----------------------|------------|--------------------------|------------|
| **Earnings Per Share —  June 30, 2009** | ** ** | **$**                   | **0.22**   | ** **            | **$**      | **0.54**                 | ** ** | **$** | **1.37** | ** ** |
|                                              |       |                    |       |                  |       |                     |       |
| **Revenues**                                      |       |                    |       |                  |       |                     |       |
| Electric on-system                                |       | $                       | 0.02       |                  | $          | 0.11                     |       | $ | (0.01 | ) |
| Electric off-system and other                     |       | 0.05                    |       | 0.09                  |       | (0.05                    | )          |
| Gas                                               |       | (0.03                   | )          | (0.09                 | )          | (0.24                    | )          |
| Other                                             |       | 0.00                    |       | 0.00                  |       | 0.01                     |       |
| **Expenses**                                      | ** ** | ** **              | ** ** | ** **            | ** ** | ** **               | ** ** |
| Electric fuel and purchased power                 |       | (0.05                   | )          | (0.12                 | )          | 0.00                     |       |
| Cost of natural gas sold and transported          |       | 0.04                    |       | 0.12                  |       | 0.26                     |       |
| Regulated — electric segment                 |       | (0.03                   | )          | (0.06                 | )          | (0.08                    | )          |
| Regulated —gas segment                       |       | 0.01                    |       | 0.01                  |       | 0.01                     |       |
| Other segment                                     |       | 0.00                    |       | 0.00                  |       | 0.00                     |       |
| Maintenance and repairs                           |       | (0.01                   | )          | (0.01                 | )          | (0.02                    | )          |
| Depreciation and amortization                     |       | (0.02                   | )          | (0.03                 | )          | (0.03                    | )          |
| Other taxes                                       |       | 0.00                    |       | (0.01                 | )          | (0.01                    | )          |
| Interest charges                                  |       | 0.01                    |       | 0.01                  |       | 0.00                     |       |
| AFUDC                                             |       | 0.02                    |       | 0.03                  |       | 0.03                     |       |
| Change in effective income tax rates              |       | (0.01                   | )          | (0.02                 | )          | 0.00                     |       |
| Med-D and cost of removal non-cash charges        |       | 0.00                    |       | (0.09                 | )          | (0.09                    | )          |
| Other income and deductions                       |       | (0.01                   | )          | (0.02                 | )          | (0.03                    | )          |
| Dilutive effect of additional shares issued       |       | (0.03                   | )          | (0.06                 | )          | (0.09                    | )          |
| **Earnings Per Share —  June 30, 2010** | ** ** | **$**                   | **0.18**   | ** **            | **$**      | **0.40**                 | ** ** | **$** | **1.03** | ** ** |

 

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**RecentActivities**

 

***Financings***

 

OnMay 28, 2010, we issued $100 million principal amount of 4.65% firstmortgage bonds due June 1, 2020. The net proceeds (after payment ofexpenses) of approximately $98.9million, were used to redeem all 2 million outstanding shares of our8.5% trust preferred securities totaling $50 million, on June 28, 2010 andto repay short-term debt which was incurred, in part, to fund the repayment, atmaturity, of our 6.5% first mortgage bonds due 2010.

 

Wesuccessfully completed our equity distribution program during the secondquarter of 2010 and used the net proceeds to repay short-term debt and forgeneral corporate purposes, including the funding of our current constructionprogram. During the second quarter of 2010, we issued and sold 1,192,644 sharesof our common stock pursuant to this equity distribution program, at an averageprice per share of $18.60, resulting in net proceeds to us of approximately$21.5 million (after payment of approximately $0.7 million in commissions tothe sales agent). Since inception of the program, in the aggregate, we issuedand sold 6,535,216 shares pursuant to the program, at an average price pershare of $18.36, resulting in net proceeds to us of approximately $116.0million.

 

OnJuly 26, 2010, we issued a notice to call all $48.3 million aggregateprincipal amount of our Senior Notes, 7.05% Series due 2022 for redemptionon August 27, 2010. We expect to finance the redemption with an offeringof first mortgage bonds. The redemption is conditioned upon the consummation ofthis offering. If we are unable to complete this offering, the notice ofredemption would be of no effect unless we waive this condition.

 

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

 

ADecember 2009 award from an arbitration panel ordered KCP&L torenegotiate with the IRS a previous $125 million advanced coal investment taxcredit granted its Iatan 2 plant. The arbitration panel agreed that we shouldhave received our 12% share of the credit as 12% owners of Iatan 2. Thearbitration panel ruled that if the IRS did not grant us our 12% share of thecredit, worth approximately $17.7 million, then KCP&L must pay us thedifference. The tax credit will have no significant income statement impact asthe credit, which will reduce our tax payments, will flow to our customers overthe life of the plant. On May 17, 2010, KCP&L filed a motion in theCircuit Court of Platte County, Missouri to vacate in part the arbitrationaward on the grounds that the arbitration panel exceeded its authority. Wefiled a motion to dismiss on the grounds that the court lacks jurisdiction overthis suit. On July 7, 2010, we received an IRS-approved memorandum ofunderstanding (MOU) between us and the IRS. Both we and KCP&L have executedrevised MOUs that await execution by the IRS. KCP&L’s challenges to thearbitration ruling remain pending in both State and Federal court.

 

***Regulatory Matters***

 

Astipulated agreement in our current Missouri electric rate case was filed on May 12,2010, calling for an annual increase of $46.8 million, provided the Plum PointGenerating Station meets its in-service criteria by August 15, 2010.Should the in-service criteria not be met, a base rate increase of $33.1million is stipulated. The new rates are to be effective September 10,2010. Both scenarios include incremental additional regulatory amortization inthe amount of $10 million that will be recorded as depreciation expense. As ofthe date of this filing, we believe that we have met all but one Plum Pointin-service criteria. The remaining test requires that the unit operate at orabove 80% of its design load for a continuous 120 hour period with emissionequipment operating effectively. Four hours of this test must be above 95%load. We currently estimate that this test will begin on or beforeAugust 8, 2010. We anticipate filing a rate case at the conclusion of thiscase to recover the Plum Point costs if necessary.

 

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 common plant needed to operate Iatan 1. We anticipate filing a rate caseat

 

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theconclusion of this case to recover the Iatan 2 costs. We have also agreed tothe use of construction accounting for our Plum Point project such as we usefor our Iatan 1 and Iatan 2 projects. However, construction accounting for PlumPoint will not apply for up to 60 days between when Plum Point becomes fullyoperational and used for service and the date tariffs in this rate case becomeeffective. 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. See Note 7 of “Notes to ConsolidatedFinancial Statements.”

 

A stipulated agreement in our current Kansas rate case was filed on May 4,2010, and approved by the KCC on June 25, 2010, calling for a $2.8million, or 12.4%, increase in base rates effective July 1, 2010. We willdefer depreciation and operating and maintenance expense on both Plum Point andIatan 2 from their respective in-service dates until the effective date forrates from the next Kansas case, expected to be an abbreviated rate case thatwill be filed within the next year. These deferrals will be recovered over a3-5 year period as determined in that next case. We will record AFUDC on allPlum Point and Iatan 2 capital expenditures incurred after January 31,2010.

 

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, or approximately 33%.

 

OnMarch 12, 2010, we filed Generation Formula Rate (GFR) tariffs with theFERC which we propose to be utilized for our wholesale customers. On May 28,2010, the FERC issued an order that conditionally approved our GFR filingsubject to refund effective June 1, 2010. On June 30, 2010, three ofour on-system wholesale customers were granted intervention in the GFR ratecase. Also on May 28, 2010, we filed a notice with the FERC requestingtermination of the current bundled service agreements for our wholesalecustomers effective July 31, 2010. On July 28, 2010, the FERC issuedan order accepting and suspending the proposed terminations for a nominalperiod to become effective July 31, 2010, subject to refund. The FERC’sorder also consolidated the GFR and termination proceedings.

 

OnFebruary 24, 2010, the MPSC unanimously approved an agreement among theOffice of the Public Counsel (OPC), the MPSC staff and us for an increase of$2.6 million in base rates for our Missouri gas customers. Pursuant to theagreement, new rates went into effect on April 1, 2010.

 

OnJune 1, 2010, we advised the Arkansas Public Service Commission of theintention to file an application for a general change or modification in ourrates, charges and tariffs no sooner than 60 days and no later than 90 daysfrom the date of notice.

 

For additional information, see “Rate Matters” below.

 

***Shareholder Rights Plan***

 

Ourshareholder rights plan, dated as of July 26, 2000, expired July 25,2010, pursuant to its terms.

 

***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

 

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ouraverage annual energy production for this unit. The loss in this facility wouldrequire us to replace it with additional generation from our gas-fired andcoal-fired units or with purchased power. The Appropriations Act requires theSouthwest Power Administration (SWPA), in coordination with us and our relevantpublic 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 newmethodology included in the draft addendum but cannot predict the finaloutcome. Originally, the Appropriations Act had a provision for the Army Corpof Engineers to provide a one time payment to us for lost energy production.This provision was revised in October 2009 to allow the SWPA to pay fordamages through a special disbursement account. Under the revised law, paymentsmust be made annually by the SWPA in an amount of at least $5 million until thetotal damages are reimbursed. On June 17, 2010, the SWPA posted a revisedFinal Determination that our customers’ damages were $26.5 million. We understandthat the SWPA intends to make a payment of at least $5 million by September 30,2010. This will have no material impact on net income as the benefits will beflowed through to our customers.

 

***Renewable Energy***

 

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. In July 2010,the MPSC submitted to the Missouri secretary of state’s office its rule forthe renewable energy mandate. We are awaiting action from the Missourisecretary of state but believe we are in compliance with the law. Kansasestablished a renewable portfolio standard (RPS) in May 2009. Its finalrulemaking is expected to be released some time in August 2010. Inaddition, there are several proposals currently before the U.S. Congress toadopt a nationwide RPS.

 

***Healthcare Reform Act - Medicare Part D benefits***

 

On March 23, 2010, the Patient Protection and Affordable Care Actwas enacted. 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 subsidywhen they provide retiree prescription benefits at least equivalent to MedicarePart D coverage in their postretirement healthcare plan. Although theelimination of this tax benefit does not take effect until 2013, this changerequires us to recognize the full accounting impact in our financial statementsin the period in which the legislation is enacted. As a result, in the firstquarter of 2010, we recorded a one-time non-cash charge of approximately $2.1million to reflect the impact of this change. Our 2010 effective tax rate alsoincreased due to the additional tax expense associated with the current yearretiree health care accruals. See Note 12 of “Notes to Consolidated FinancialStatements.”

 

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**RESULTS OF OPERATIONS**

 

The following discussion analyzes significant changes in the results ofoperations for the three-month, six-month and twelve-month periods ended June 30,2010, compared to the same periods ended June 30, 2009.

 

Thefollowing table represents our results of operations by operating segment forthe applicable periods ended June 30 (in millions):

 
| ** ** | ** ** | **Quarter Ended** | ** ** | **Six Months Ended** | ** ** | **Twelve Months Ended** | ** ** |
|------------|------------|------------------------|------------|--------------------------------|------------|-----------------------------------|------------|
| ** ** | ** ** | **2010**               | ** ** | **2009**                       | ** ** | **2010**                          | ** ** | **2009** | ** ** | **2010** | ** ** | **2009** | ** ** |
| Electric   |       | $                      | 7.4        |                           | $          | 8.0                               |       | $ | 13.3 |   | $ | 16.8 |   | $ | 35.5 |   | $ | 44.8 |   |
| Gas        |       | (0.4                   | )          | (0.8                           | )          | 2.0                               |       | 1.0 |   | 1.8 |   | 0.9 |   |
| Other      |       | 0.4                    |       | 0.4                            |       | 0.7                               |       | 0.7 |   | 1.4 |   | 0.8 |   |
| Net income |       | $                      | 7.4        |                           | $          | 7.6                               |       | $ | 16.0 |   | $ | 18.5 |   | $ | 38.7 |   | $ | 46.5 |   |

 

----

**Differences could occur due to rounding.*

 

***Electric Segment***

 

**Overview**

 

Our electric segment income for the second quarter of 2010 was $7.4million as compared to $8.0 million for the second quarter of 2009.

 

Electric operating revenues comprised approximately 92.8% of our totaloperating revenues during the second quarter of 2010. Of our total electricoperating revenues during the second quarter of 2010, approximately 38.0% werefrom residential customers, 32.7% from commercial customers, 16.1% fromindustrial customers, 4.3% from wholesale on-system customers, 4.8% fromwholesale off-system transactions, 2.6% from other electric revenues, primarilypublic authorities, and 1.5% from miscellaneous sources. The percentage ofrevenues provided from our wholesale off-system transactions increased duringthe second quarter of 2010 as compared to the second quarter of 2009, primarilydue to increased market demand resulting from the warmer weather in May andJune of 2010.

 

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 June 30,were as follows:

 
| ** **            | ** ** | **kWh Sales**     | ** ** |
|-----------------------|------------|-------------------|------------|
| ** **            | ** ** | **(in millions)** | ** ** |
| ** **            | ** ** | **Second**        | ** ** | **Second** | ** ** | ** ** | ** ** | **6 Months** | ** ** | **6 Months** | ** ** | ** ** | ** ** | **12 Months** | ** ** | **12 Months** | ** ** | ** ** | ** ** |
| ** **            | ** ** | **Quarter**       | ** ** | **Quarter** | ** ** | **%** | ** ** | **Ended** | ** ** | **Ended** | ** ** | **%** | ** ** | **Ended** | ** ** | **Ended** | ** ** | **%** | ** ** |
| **Customer  Class**   | ** ** | **2010**          | ** ** | **2009** | ** ** | **Change*** | ** ** | **2010** | ** ** | **2009** | ** ** | **Change*** | ** ** | **2010** | ** ** | **2009** | ** ** | **Change*** | ** ** |
| Residential           |       | 396.3             |       | 387.2 |   | 2.4 | % | 1,035.6 |   | 938.1 |   | 10.4 | % | 1,963.9 |   | 1,915.9 |   | 2.5 | % |
| Commercial            |       | 405.6             |       | 403.9 |   | 0.4 |   | 791.3 |   | 779.9 |   | 1.5 |   | 1,591.2 |   | 1,630.5 |   | (2.4 | ) |
| Industrial            |       | 259.4             |       | 252.0 |   | 2.9 |   | 490.4 |   | 492.3 |   | (0.4 | ) | 990.3 |   | 1,034.0 |   | (4.2 | ) |
| Wholesale on-system   |       | 85.4              |       | 82.7 |   | 3.2 |   | 170.3 |   | 163.5 |   | 4.2 |   | 338.9 |   | 339.0 |   | (0.1 | ) |
| Other**               |       | 29.5              |       | 29.8 |   | (1.0 | ) | 63.3 |   | 62.0 |   | 2.2 |   | 124.8 |   | 123.7 |   | 0.8 |   |
| Total on-system sales |       | 1,176.2           |       | 1,155.6 |   | 1.8 |   | 2,550.9 |   | 2,435.8 |   | 4.7 |   | 5,009.1 |   | 5,043.1 |   | (0.7 | ) |
| Off-system            |       | 213.3             |       | 111.9 |   | 90.7 |   | 395.8 |   | 245.7 |   | 61.1 |   | 666.0 |   | 624.1 |   | 6.7 |   |
| Total KWh Sales       |       | 1,389.5           |       | 1,267.5 |   | 9.6 |   | 2,946.7 |   | 2,681.5 |   | 9.9 |   | 5,675.1 |   | 5,667.2 |   | 0.1 |   |

 

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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)**                          | ** ** |
| ** **                                | ** ** | **Second**                                             | ** ** | **Second** | ** ** | ** ** | ** ** | **6 Months** | ** ** | **6 Months** | ** ** | ** ** | ** ** | **12 Months** | ** ** | **12 Months** | ** ** | ** ** | ** ** |
| ** **                                | ** ** | **Quarter**                                            | ** ** | **Quarter** | ** ** | **%** | ** ** | **Ended** | ** ** | **Ended** | ** ** | **%** | ** ** | **Ended** | ** ** | **Ended** | ** ** | **%** | ** ** |
| **Customer  Class**                       | ** ** | **2010**                                               | ** ** | **2009** | ** ** | **Change*** | ** ** | **2010** | ** ** | **2009** | ** ** | **Change*** | ** ** | **2010** | ** ** | **2009** | ** ** | **Change*** | ** ** |
| Residential                               |       | $                                                      | 40.4       |   | $ | 39.5 |   | 2.3 | % | $ | 94.4 |   | $ | 88.1 |   | 7.2 | % | $ | 186.7 |   | $ | 182.4 |   | 2.4 | % |
| Commercial                                |       | 34.8                                                   |       | 35.3 |   | (1.3 | ) | 64.5 |   | 64.9 |   | (0.6 | ) | 135.4 |   | 138.2 |   | (2.0 | ) |
| Industrial                                |       | 17.1                                                   |       | 16.8 |   | 1.8 |   | 31.2 |   | 31.7 |   | (1.6 | ) | 65.5 |   | 67.6 |   | (3.1 | ) |
| Wholesale on-system                       |       | 4.5                                                    |       | 4.3 |   | 5.0 |   | 9.5 |   | 9.0 |   | 5.1 |   | 18.7 |   | 18.7 |   | (0.5 | ) |
| Other**                                   |       | 2.8                                                    |       | 2.7 |   | 1.0 |   | 5.6 |   | 5.5 |   | 2.4 |   | 11.7 |   | 11.4 |   | 3.1 |   |
| Total on-system revenues                  |       | $                                                      | 99.6       |   | $ | 98.6 |   | 1.0 |   | $ | 205.2 |   | $ | 199.2 |   | 3.0 |   | $ | 418.0 |   | $ | 418.3 |   | (0.1 | ) |
| Off-system                                |       | 5.1                                                    |       | 2.6 |   | 94.5 |   | 11.3 |   | 6.6 |   | 71.8 |   | 19.1 |   | 21.5 |   | (11.2 | ) |
| Total revenues from kWh sales             |       | 104.7                                                  |       | 101.2 |   | 3.4 |   | 216.5 |   | 205.8 |   | 5.2 |   | 437.1 |   | 439.8 |   | (0.6 | ) |
| Miscellaneous revenues***                 |       | 1.6                                                    |       | 1.4 |   | 10.5 |   | 3.3 |   | 3.2 |   | 3.4 |   | 6.9 |   | 6.9 |   | 0.5 |   |
| Total electric operating revenues         |       | $                                                      | 106.3      |   | $ | 102.6 |   | 3.5 |   | $ | 219.8 |   | $ | 209.0 |   | 5.2 |   | $ | 444.0 |   | $ | 446.7 |   | (0.6 | ) |
| Water revenues                            |       | 0.4                                                    |       | 0.5 |   | 0.4 |   | 0.9 |   | 0.9 |   | 1.2 |   | 1.7 |   | 1.7 |   | 0.5 |   |
| Total electric segment operating revenues |       | $                                                      | 106.7      |   | $ | 103.1 |   | 3.5 |   | $ | 220.7 |   | $ | 209.9 |   | 5.2 |   | $ | 445.7 |   | $ | 448.4 |   | (0.6 | ) |

 

----

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

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

****Miscellaneous revenues include transmission service revenue, latepayment fees, renewable energy credit sales, rent, etc.*

 

***Quarter Ended June 30, 2010 Compared toQuarter Ended June 30, 2009***

 

**On-System Operating Revenues and Kilowatt-Hour Sales**

 

KWh sales for our on-system customers increased during the secondquarter of 2010 as compared to the second quarter of 2009 primarily due tofavorable weather and customer growth. Revenues for our on-system customersincreased approximately $1.0 million, or 1.0%, primarily due to favorableweather in the second quarter of 2010. Weather and other related factorsincreased revenues by an estimated $0.8 million compared to last year’s secondquarter. Total cooling degree days (the cumulative number of degrees that theaverage temperature for each day during that period was above 65*°* F) for the second quarter of 2010 were 29.7% morethan the same period last year and 51.2% more than the 30-year average, mainlydue to unseasonably hot weather in May and June of 2010. Customergrowth contributed an estimated $0.5 million of the increase in revenues. Ourelectric customer growth for the twelve months ended June 30, 2010 was0.5%. Rate changes had a negative effect of an estimated $0.3 million duringthe second quarter of 2010.

 

Residential kWh sales and related revenues increased during the secondquarter of 2010 due to the favorable weather and increased customer growth.

 

Commercial kWh sales increased during the second quarter of 2010 due tothe favorable weather and increased customer growth, while the related revenuesdecreased.

 

Industrial kWh sales and revenues increased during the second quarterof 2010 as compared to the second quarter of 2009.

 

On-system wholesale kWh sales and revenues increased during the secondquarter of 2010 as compared to the same period in 2009 reflecting the warmerweather in May and June of 2010.

 

**Off-System Electric Transactions**

 

Inaddition to sales to our own customers, we also sell power to other utilitiesas available, including through the Southwest Power Pool (SPP) energy imbalanceservices (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 income.

 

Off-system revenues and related expenses were more during the secondquarter of 2010 as compared to the second quarter of 2009 primarily due toincreased market demand resulting from 

 

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the warmer weather in May and June of 2010. Total purchasedpower related expenses are included in our discussion of purchased power costsbelow.

 

**Miscellaneous Revenues**

 

Our miscellaneous revenues were $1.6 million for the second quarter of2010 as compared to $1.4 million in the second quarter of 2009. These revenuesare comprised mainly of transmission revenues, late payment fees and renewableenergy credit sales.

 

**Operating Revenue Deductions**

 

During the second quarter of 2010, total electric segment operatingexpenses increased approximately $5.7 million (6.5%) compared with the sameperiod last year.

 

Totalfuel and purchased power expenses increased approximately $2.7 million (6.5%)during the second 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 second quarter of 2010 and 2009.

 
| **(in  millions)**                                           | ** ** | **2010** | ** ** | **2009** | ** ** |
|--------------------------------------------------------------|------------|----------|------------|----------|------------|
| Actual fuel and purchased power expenditures                 |       | $        | 44.8       |     | $          | 38.7 |   |
| Kansas regulatory adjustments*                               |       | —   |       | 0.1      |       |
| Missouri fuel adjustment deferral*                           |       | (0.7     | )          | 2.6      |       |
| Missouri fuel adjustment recovery**                          |       | —   |       | 0.1      |       |
| Unrealized loss on derivatives                               |       | 0.1      |       | —   |       |
| Total fuel and purchased power expense per income  statement |       | $        | 44.2       |     | $          | 41.5 |   |

 

----

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

**Currently being recovered from customers from prior accumulationperiods.

 

Theoverall fuel and purchased power increase reflects increased generation by bothour gas fired and coal fired units and a decrease in purchased power volumethat was offset by an increase in purchased power prices in the second quarter of2010 as compared to 2009. The increase in fuel costs includes the effect ofincreased market demand resulting from warmer weather in the second 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 second quarter of 2010 as comparedto the second quarter of 2009. This table incorporates all the changesmentioned above. As shown below, the largest impact on fuel and purchased powercosts was increased generation by our gas-fired units.

 
| **(in  millions)**                   | ** ** | **Three Months Ended  June 30, 2010 vs. 2009** | ** ** |
|--------------------------------------|------------|-----------------------------------------------------|------------|
| Natural gas generation volume        |       | $                                                   | 9.8        |   |
| Coal generation volume               |       | 0.3                                                 |       |
| Purchased power spot purchase volume |       | (1.1                                                | )          |
| Purchased power (cost per mWh)       |       | 2.3                                                 |       |
| Natural gas (cost per mWh)           |       | (4.7                                                | )          |
| Coal (cost per mWh)                  |       | (0.4                                                | )          |
| Other (primarily fuel adjustments)   |       | (3.5                                                | )          |
| TOTAL                                |       | $                                                   | 2.7        |   |

 

Regulatedoperating expenses increased approximately $1.5 million (9.4%) during thesecond quarter of 2010 as compared to the same period in 2009 primarily due toincreases of $0.4 million in transmission and distribution expense, $0.3million in professional services, $0.3 million in employee health care expense,$0.2 million in employee pension expense, $0.2 million in other power supplyexpense, $0.2 million in customer accounts expense (mainly increased bankingfees), 

 

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$0.1million in general labor costs and $0.1 million in director, stockholder andother investor expense.****Theseincreases were partially offset by $0.3 million in other steam power expenserelated to Iatan 1 operating costs that we were able to defer in accordancewith our agreement with the MPSC that allows deferral of certain costs untilthe environmental upgrades to Iatan 1 are included in our rate base.

 

Maintenance and repairs expense increased approximately $0.7 million(7.9%) in the second quarter of 2010 as compared to 2009 primarily due toincreases of $0.5 million in maintenance and repairs expense at the Rivertonplant due to the 5-year maintenance outage which began on March 20, 2010and ended May 21, 2010, $0.3 million in maintenance and repairs expense atthe Asbury plant mainly due to a maintenance outage in May 2010, $0.3million in distribution maintenance, and $0.2 million in maintenance andrepairs expense at the Iatan plant. These increases were partially offset by a$0.7 million decrease in maintenance and repairs expense at the State LineCombined Cycle (SLCC) Plant.

 

Depreciation and amortization expense increased approximately $0.5million (4.1%) during the quarter primarily reflecting our additions to plantin service. This includes the construction accounting effect of deferring $0.3million of Iatan 1 depreciation expense. Other taxes increased approximately$0.1 million during the second quarter of 2010 due to increased property taxreflecting our additions to plant in service and increased municipal franchisetaxes.

 

***Six Months Ended June 30, 2010 Compared to SixMonths Ended June 30, 2009***

 

**On-System Operating Revenues and Kilowatt-Hour Sales**

 

KWh sales for our on-system customers increased during the six monthsended June 30, 2010 as compared to the six months ended June 30, 2009primarily due to colder weather in the first quarter of 2010 and warmer weatherin the second quarter of 2010 as compared to the same periods in 2009. Revenuesfor our on-system customers increased approximately $6.0 million, or 3.0%.Weather and other related factors increased revenues by an estimated $7.6million during the six months ended June 30, 2010 compared to the sixmonths ended June 30, 2009. Customer growth contributed an estimated $0.9million to revenues while rate changes had a negative effect of an estimated$2.5 million during the six months ended June 30, 2010.

 

The increase in residential kWh sales and revenues during the sixmonths ended June 30, 2010 was primarily due to the weather conditions andcustomer growth discussed above.

 

Commercial kWh sales increased during the six months ended June 30,2010 due to the favorable weather and increased customer growth, while therelated revenues decreased.

 

Industrial kWh sales and revenues decreased mainly due to a slowdowncontinuing in the first quarter of 2010 created by economic uncertainty**.**

 

On-system wholesale kWh sales increased 4.2% and revenues increased5.1% during the six months ended June 30, 2010 reflecting the weatherconditions discussed above.

 

**Off-System Electric Transactions**

 

Off-system revenues and related expenses were more during the sixmonths ended June 30, 2010 as compared to the same period in 2009primarily due to increased market demand resulting from the warmer weather in May andJune of 2010 and colder weather in the first quarter of 2010. Totalpurchased power related expenses are included in our discussion of purchasedpower costs below.

 

**Miscellaneous Revenues**

 

Our miscellaneous revenues were $3.3 million for the six months ended June 30,2010 as compared to $3.2 million during the same period in 2009. These revenuesare comprised mainly of transmission revenues, late payment fees and renewableenergy credit sales.

 

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** **

**Operating Revenue Deductions**

 

During the six months ended June 30, 2010, total electric segmentoperating expenses increased approximately $16.2 million (9.1%) compared withthe same period last year.

 

Totalfuel and purchased power expenses increased approximately $6.6 million (7.5%)during the six months ended June 30, 2010. The table below is areconciliation of our actual fuel and purchased power expenditures (netted withthe regulatory adjustments) to the fuel and purchased power expense shown onour statement of operations for the six months ended June 30, 2010 and2009.

 
| **(in  millions)**                                           | ** ** | **2010** | ** ** | **2009** | ** ** |
|--------------------------------------------------------------|------------|----------|------------|----------|------------|
| Actual fuel and purchased power expenditures                 |       | $        | 98.0       |     | $          | 88.4 |   |
| Kansas regulatory adjustments*                               |       | (0.4     | )          | 0.4      |       |
| Missouri fuel adjustment deferral*                           |       | (2.6     | )          | (0.5     | )          |
| Missouri fuel adjustment recovery**                          |       | (0.5     | )          | 0.1      |       |
| Unrealized loss on derivatives                               |       | 0.4      |       | —   |       |
| Total fuel and purchased power expense per income  statement |       | $        | 94.9       |     | $          | 88.4 |   |

 

----

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

**Currently being refunded to customers from prior accumulationperiods.

 

Theoverall fuel and purchased power increase reflects increased market demandresulting from the warmer weather in May and June of 2010 and colderweather in the first quarter of 2010 as compared to the prior year periods.

 

Summarizedin the table below are our estimated cost and volume changes in the componentsof fuel and purchased power expenses for the six months ended June 30,2010 as compared to the six months ended June 30, 2009. This tableincorporates all the changes mentioned above. As shown below, the largest impacton fuel and purchased power costs was increased generation by our gas-firedunits.

 
| **(in  millions)**                   | ** ** | **Six Months Ended  June 30, 2010 vs. 2009** | ** ** |
|--------------------------------------|------------|---------------------------------------------------|------------|
| Natural gas generation volume        |       | $                                                 | 15.7       |   |
| Coal generation volume               |       | 2.3                                               |       |
| Purchased power spot purchase volume |       | (3.5                                              | )          |
| Purchased power (cost per mWh)       |       | 2.8                                               |       |
| Natural gas (cost per mWh)           |       | (7.1                                              | )          |
| Coal (cost per mWh)                  |       | (0.5                                              | )          |
| Other (primarily fuel adjustments)   |       | (3.1                                              | )          |
| TOTAL                                |       | $                                                 | 6.6        |   |

 

Regulatedoperating expenses for our electric segment increased approximately $3.1 million(10.0%) during the six months ended June 30, 2010 as compared to the sameperiod in 2009 primarily due to increases of $0.6 million in transmission anddistribution expense, $0.5 million in employee health care expense, $0.5million in customer accounts expenses (mainly increased banking fees), $0.4million in general labor costs, $0.3 million in employee pension expense, $0.2million in property insurance, $0.2 million in professional services, $0.1million in injuries and damages, $0.1 million in general office expense, $0.1million in other power operation expense, $0.1 million in customer assistanceexpense, $0.1 million in director, stockholder and other investor expense and$0.1 million in research and development expense. These increases were partiallyoffset by $0.6 million in other steam power expense related to Iatan 1operating costs that we were able to defer in accordance with our agreementwith the MPSC that allows deferral of certain costs until the environmentalupgrades to Iatan 1 are included in our rate base.

 

Maintenance and repairs expense increased approximately $0.8 million(4.7%) during the six months ended June 30, 2010 as compared to 2009primarily due to increases of $0.9 million in maintenance and repairs expenseat the Riverton plant due to the 2010 5-year maintenance outage, $0.4 millionin maintenance and repairs expense at the Asbury plant mainly due to amaintenance 

 

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outage in May 2010, $0.4 million in distribution maintenance, $0.3million in maintenance and repairs expense at the Iatan plant and $0.2 millionin transmission maintenance. These increases were almost entirely offset by a$1.5 million decrease in maintenance and repairs expense at the SLCC plant ascompared to 2009 when there was a maintenance outage at the plant in the firstquarter.

 

Depreciation and amortization expense increased approximately $1.0million (4.0%) during the six months ended June 30, 2010 primarilyreflecting our additions to plant in service. This includes the constructionaccounting effect of deferring $0.7 million of Iatan 1 depreciation expense.Other taxes increased approximately $0.6 million during the six months ended June 30,2010 due to increased property tax reflecting our additions to plant in serviceand increased municipal franchise taxes.

 

***Twelve Months Ended June 30, 2010 Compared toTwelve Months Ended June 30, 2009***

 

**On-System Operating Revenues and Kilowatt-Hour Sales**

 

For the twelve months ended June 30, 2010, kWh sales to ouron-system customers decreased 0.7% with the associated revenues decreasingapproximately $0.3 million (0.1%). Weather and other related factors decreasedrevenues an estimated $6.1 million. Rate changes, primarily the August 2008Missouri rate increase (discussed below), contributed an estimated $4.8 millionto revenues while continued customer growth contributed an estimated $1.0million. The increase in residential kWh sales and revenues during the twelvemonths ended June 30, 2010 was primarily due to colder weather in thefirst quarter of 2010 and warmer weather in the second quarter of 2010 whilethe increase in residential revenues was also due to the 2008 Missouri rateincrease. Industrial and commercial kWh sales and revenues decreased during thetwelve months ended June 30, 2010, mainly due to general economicconditions. On-system wholesale kWh sales and revenues decreased slightlyduring the twelve months ended June 30, 2010 reflecting the generaleconomic conditions.

 

**Off-System Electric Transactions**

 

Off-system revenues decreased $2.4 million during the twelve monthsended June 30, 2010 as compared to the same period in 2009 primarily dueto decreased market demand and lower gas prices in the third and fourthquarters of 2009. Total purchased power related expenses are included in ourdiscussion of purchased power costs below.

 

**Miscellaneous Revenues**

 

Our miscellaneous revenues were $6.9 million for both the twelve monthsended June 30, 2010 and the twelve months ended June 30, 2009. Theserevenues are comprised mainly of transmission revenues, late payment fees andrenewable energy credit sales.

** **

**Operating Revenue Deductions**

 

During the twelve months ended June 30, 2010, total electricsegment operating expenses increased approximately $7.2 million (1.9%) comparedto the prior period.

 

Totalfuel and purchased power expenses increased approximately $0.1 million (0.1%)during the twelve months ended June 30, 2010. The table below is areconciliation of our actual fuel and purchased power expenditures (netted withthe regulatory adjustments) to the fuel and purchased power expense shown onour statement of income for the twelve months ended June 30, 2010 and2009.

 

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| **(in  millions)**                                           | ** ** | **2010** | ** ** | **2009** | ** ** |
|--------------------------------------------------------------|------------|----------|------------|----------|------------|
| Actual fuel and purchased power expenditures                 |       | $        | 191.7      |     | $          | 188.1 |   |
| Kansas regulatory adjustments*                               |       | (0.2     | )          | 0.3      |       |
| Missouri fuel adjustment deferral*                           |       | (4.0     | )          | (0.3     | )          |
| Missouri fuel adjustment recovery**                          |       | 1.0      |       | 0.1      |       |
| Unrealized loss on derivatives                               |       | 0.1      |       | 0.3      |       |
| Total fuel and purchased power expense per income  statement |       | $        | 188.6      |     | $          | 188.5 |   |

 

----

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

**Currently being recovered from customers from prior accumulationperiods.

 

Theoverall fuel and purchased power increase includes the effect of decreasedmarket demand resulting from mild weather in the third and fourth quarters of2009 offset by increased demand in the first and second quarters of 2010 due tofavorable weather conditions.

 

Summarizedin the table below are our estimated cost and volume changes in the componentsof fuel and purchased power expenses for the twelve months ended June 30,2010 as compared to the twelve months ended June 30, 2009. This tableincorporates all the changes mentioned above. As shown below, the increases infuel costs were offset by decreases in volume and in fuel adjustments.

 
| **(in  millions)**                   | ** ** | **Twelve Months Ended  June 30, 2010 vs. 2009** | ** ** |
|--------------------------------------|------------|------------------------------------------------------|------------|
| Coal generation volume               |       | $                                                    | 3.2        |   |
| Natural gas generation volume        |       | (2.5                                                 | )          |
| Purchased power spot purchase volume |       | (2.1                                                 | )          |
| Natural gas (cost per mWh)           |       | 3.3                                                  |       |
| Purchased power (cost per mWh)       |       | 1.3                                                  |       |
| Coal (cost per mWh)                  |       | 0.4                                                  |       |
| Other (primarily fuel adjustments)   |       | (3.5                                                 | )          |
| TOTAL                                |       | $                                                    | 0.1        |   |

 

Regulatedoperating expenses increased approximately $4.3 million (6.9%) during thetwelve months ended June 30, 2010 as compared to the same period in 2009primarily due to increases of****$1.2 millionin professional services, $1.1 million in general labor costs, $0.8 million intransmission and distribution expense, $0.7 million in customer accountsexpense (mainly increased banking fees), $0.5 million in employee health careexpense, $0.4 million in employee pension expense, $0.4 million in other steampower expense at the Iatan 1 plant, $0.2 million in other steam power expenseat the Asbury plant, $0.3 million in property insurance, $0.2 million inemployee welfare costs, $0.2 million in other power operation expense, $0.1million in research and development expense and $0.1 million in director,stockholder and other investor expense. These increases were partially offsetby $1.2 million in other steam power expense related to Iatan 1 operating coststhat we were able to defer 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. Decreases of $0.7 million in injuries anddamages and $0.1 million in regulatory commission expense also decreasedexpenses.

 

Maintenanceand repairs expense increased approximately $1.0 million (3.1%) during thetwelve months ended June 30, 2010 as compared to 2009 primarily due toincreases of $1.6 million in transmission and distribution maintenance(including $0.6 million of ice storm-related amortization), $1.0 million inmaintenance and repairs expense at the Asbury plant mainly due to a maintenanceoutage in May 2010, $0.6 million in maintenance and repairs expense at theRiverton plant due to the 2010 5-year maintenance outage, $0.1 million inmaintenance and repairs expense at the Ozark Beach plant and $0.2 million inrepairs expense to the Riverton gas units. These increases were partiallyoffset by decreases of $2.1 million in maintenance and repairs expense to theSLCC which experienced a maintenance outage in the first quarter of 2009 and$0.4 million in 

 

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maintenanceand repairs expense at the Iatan 1 plant, which experienced an outage in thefourth quarter of 2008.

 

Depreciation and amortization expense increased approximately $0.8million (1.8%) during the twelve months ended June 30, 2010 reflecting ouradditions to plant in service. This includes the construction accounting effectof deferring $1.3 million of Iatan 1 depreciation expense. Other taxesincreased approximately $0.9 million during the twelve months ended June 30,2010 due to increased property tax reflecting our additions to plant in serviceand increased municipal franchise taxes.

 

***Gas Segment***

 

**Gas Operating Revenues and Sales**

 

The following tables detailour natural gas sales and revenues for the periods ended June 30:

 

**Total Gas Delivered toCustomers**

 
| ** **                | ** ** | **Three Months Ended** | ** ** | **%**    | ** ** | **Six months ended** | ** ** | **%**    | ** ** | **Twelve months ended** | ** ** | **%**      | ** ** |
|---------------------------|------------|------------------------|------------|----------|------------|----------------------|------------|----------|------------|-------------------------|------------|------------|------------|
| **(bcf  sales)**          | ** ** | **2010**               | ** ** | **2009** | ** ** | **change**           | ** ** | **2010** | ** ** | **2009**                | ** ** | **Change** | ** ** | **2010** | ** ** | **2009** | ** ** | **change** | ** ** |
| Residential               |       | 0.19                   |       | 0.29     |       | (32.9                | )%         | 1.71     |       | 1.60                    |       | 6.6        | %          | 2.79 |   | 2.70 |   | 3.5 | % |
| Commercial                |       | 0.12                   |       | 0.15     |       | (22.9                | )          | 0.77     |       | 0.72                    |       | 7.0        |       | 1.33 |   | 1.28 |   | 3.8 |   |
| Industrial*               |       | 0.02                   |       | 0.02     |       | 1.9                  |       | 0.06     |       | 0.17                    |       | (64.6      | )          | 0.11 |   | 0.52 |   | (79.1 | ) |
| Other**                   |       | 0.00                   |       | 0.00     |       | (51.6                | )          | 0.02     |       | 0.02                    |       | 25.0       |       | 0.04 |   | 0.03 |   | 13.5 |   |
| Total retail sales        |       | 0.33                   |       | 0.46     |       | (28.5                | )          | 2.56     |       | 2.51                    |       | 2.1        |       | 4.27 |   | 4.53 |   | (5.8 | ) |
| Transportation sales      |       | 1.09                   |       | 0.92     |       | 17.6                 |       | 2.69     |       | 2.08                    |       | 29.2       |       | 4.93 |   | 3.94 |   | 25.4 |   |
| Total gas operating sales |       | 1.42                   |       | 1.38     |       | 2.2                  |       | 5.25     |       | 4.59                    |       | 14.4       |       | 9.20 |   | 8.47 |   | 8.7 |   |

** **

**Operating Revenues andCost of Gas Sold**

 
| ** **                                       | ** ** | **Three Months Ended** | ** ** | ** ** | ** ** | **Six months ended** | ** ** | ** ** | ** ** | **Twelve months ended** | ** ** | ** **   | ** ** |
|--------------------------------------------------|------------|------------------------|------------|------------|------------|----------------------|------------|------------|------------|-------------------------|------------|--------------|------------|
| **($ in  millions)**                        | ** ** | **2010**               | ** ** | **2009**   | ** ** | **% change**         | ** ** | **2010**   | ** ** | **2009**                | ** ** | **% change** | ** ** | **2010** | ** ** | **2009** | ** ** | **% change** | ** ** |
| Residential                                      |       | $                      | 3.9        |       | $          | 4.9                  |       | (20.6      | )%         | $                       | 20.1       |         | $          | 23.0 |   | (12.4 | )% | $ | 33.3 |   | $ | 39.5 |   | (15.6 | )% |
| Commercial                                       |       | 1.6                    |       | 2.1        |       | (25.6                | )          | 8.1        |       | 9.5                     |       | (14.6        | )          | 14.2 |   | 17.3 |   | (18.1 | ) |
| Industrial*                                      |       | 0.1                    |       | 0.2        |       | (41.3                | )          | 0.5        |       | 1.6                     |       | (71.8        | )          | 0.9 |   | 4.9 |   | (81.3 | ) |
| Other**                                          |       | 0.0                    |       | 0.0        |       | (41.7                | )          | 0.3        |       | 0.3                     |       | (1.3         | )          | 0.4 |   | 0.4 |   | (10.4 | ) |
| Total retail revenues                            |       | $                      | 5.6        |       | $          | 7.2                  |       | (22.8      | )          | $                       | 29.0       |         | $          | 34.4 |   | (15.7 | ) | $ | 48.8 |   | $ | 62.1 |   | (21.5 | ) |
| Other revenues                                   |       | 0.1                    |       | 0.0        |       | 189.3                |       | 0.2        |       | 0.1                     |       | 65.9         |       | 0.3 |   | 0.2 |   | 38.2 |   |
| Transportation revenues*                         |       | 0.8                    |       | 0.7        |       | 22.2                 |       | 1.9        |       | 1.5                     |       | 24.7         |       | 3.3 |   | 2.7 |   | 23.0 |   |
| Total gas operating revenues                     |       | $                      | 6.5        |       | $          | 7.9                  |       | (17.7      | )          | $                       | 31.1       |         | $          | 36.0 |   | (13.7 | ) | $ | 52.4 |   | $ | 65.0 |   | (19.4 | ) |
| Cost of gas sold                                 |       | 2.3                    |       | 4.2        |       | (46.2                | )          | 17.4       |       | 23.5                    |       | (26.1        | )          | 29.5 |   | 43.1 |   | (31.7 | ) |
| Gas operating revenues over cost of gas in rates |       | $                      | 4.2        |       | $          | 3.7                  |       | 14.6       |       | $                       | 13.7       |         | $          | 12.5 |   | 9.7 |   | $ | 22.9 |   | $ | 21.9 |   | 4.8 |   |

 

----

**Percentagechange for six months ended and twelve months ended reflects the transfer of a customer from transportation toindustrial sales in April 2008 and back to transportation in April 2009and a customer switching from industrial sales to transportation in October 2009after an eight-month suspension.*

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

 

***Quarter Ended June 30, 2010 Compared toQuarter Ended June 30, 2009***

 

**Operating Revenues and bcf Sales**

 

Gas retail sales decreasedduring the second quarter of 2010 as compared to 2009 primarily due to warmerweather in the second quarter of 2010. Gas sales are less during the summermonths as the heating season runs from November to March of eachyear. Residential and commercial sales decreased during the second quarter of2010 as compared to the second quarter of 2009 primarily due to the weather.Heating degree days were 35.3% lower in the second quarter of 2010 as comparedto the second quarter of 2009 and 35.0% lower than the 30-year average mainlydue to unseasonably warm weather in April of 2010. Industrial sales, whichare not as 

 

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weather sensitive, increasedslightly during the second quarter of 2010 as compared to the same period in2009.

 

Duringthe second quarter of 2010, gas segment revenues were approximately $6.5million as compared to $7.9 million in the second quarter of 2009 despite arate increase of $2.6 million that went into effect on April 1, 2010 (see “Rate Matters” below). Our PGA revenue(which represents the cost of gasrecovered from our customers) was approximately $2.3 million as comparedto $4.2 million in the second quarter of 2009, a decrease of approximately $1.9million. This decrease was largely driven by the decreases in the PGAs thatwent into effect May 15, 2009 and November 13, 2009. Total retailsales decreased 28.5% while the corresponding revenues decreased only 22.8%.This was due to the April 2010 rate change that caused a greaterallocation of margin to be shifted into the customer charge and less to salesvolumes.

 

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 June 30, 2010, we hadunder recovered purchased gas costs of $0.2 million recorded as a regulatoryasset and over recovered purchased gas costs of $2.7 million recorded as aregulatory liability.

 

**OperatingRevenue Deductions**

 

Totalother operating expenses were approximately $2.3 million during the secondquarter of 2010 as compared to $2.6 million in the first quarter of 2009, adecrease of $0.3 million. This decrease was mainly due to a $0.2 milliondecrease in employee pension expense and a $0.1 million decrease in director,stockholder and other investor expense.

 

Ourgas segment had a net loss of $0.4 million for the second quarter of 2010 ascompared to a net loss of $0.8 million for the second quarter of 2009.

 

***Six Months Ended June 30, 2010 Compared to SixMonths Ended June 30, 2009***

 

**Operating Revenues and bcf Sales**

 

Gas retail sales increasedduring the six months ended June 30, 2010 as compared to the same periodin 2009 mainly due to colder weather in the first quarter of 2010. Residentialand commercial sales increased during the six months ended June 30, 2010as compared to the same period in 2009 primarily due to the colder weather.Industrial sales decreased during the six months ended June 30, 2010 ascompared to the same period in 2009 mainly due to the switching of customers between industrial sales and transportation and thesuspension of operations of a large volume sales customer (see footnote above).

 

During the six months ended June 30,2010, gas segment revenues were approximately $31.1 million as compared to$36.0 million in the six months ended June 30, 2009, a decrease of $4.9million. This decrease was largely driven by the PGAs that went into effect May 15,2009 and November 13, 2009. During the six months ended June 30, 2010,our PGA revenue was approximately $17.4 million as compared to $23.5 millionduring the six months ended June 30, 2009, a decrease of approximately$6.1 million.

 

**OperatingRevenue Deductions**

 

Totalother operating expenses were $5.0 million for the six months ended June 30,2010 as compared to $5.4 million for the six months ended June 30, 2009.This decrease was mainly due to a $0.2 million decrease in employee pensionexpense and a $0.2 million decrease in customer accounts expense, primarily baddebt expense.

 

Ourgas segment had net income of $1.9 million for the six months ended June 30,2010 as compared to $1.0 million for the six months ended June 30, 2009.

 

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***Twelve Months Ended June 30, 2010 Compared toTwelve Months Ended June 30, 2009***

 

**Operating Revenues and bcf Sales**

 

Gas retail sales decreasedduring the twelve months ended June 30, 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 0.7% for the twelve months ended June 30,2010. 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 June 30, 2010 primarily due tocolder weather in the first quarter of 2010.

 

During the twelve monthsended June 30, 2010, gas segment revenues were approximately $52.4 millionas compared to $65.0 million in the twelve months ended June 30, 2009, adecrease of $12.6 million. This decrease was largely driven by a decrease inthe PGAs that went into effect May 15, 2009 and November 13, 2009.During the twelve months ended June 30, 2010, our PGA revenue wasapproximately $29.5 million as compared to $43.1 million during the twelvemonths ended June 30, 2009, a decrease of approximately $13.7 million.

 

**OperatingRevenue Deductions**

 

Totalother operating expenses were $9.8 million for the twelve months ended June 30,2010 as compared to $10.4 million for the twelve months ended June 30,2009. This decrease was mainly due to a $0.3 million decrease in customeraccounts expense, primarily bad debt expense and a $0.3 million decrease inemployee pension expense.

 

Ourgas segment had net income of $1.8 million for the twelve months ended June 30,2010 as compared to $0.9 million for the twelve months ended June 30,2009.

 

***Consolidated Company***

 

**Income Taxes**

 

Thefollowing table shows the increases in our consolidated provision for incometaxes (in millions) for the applicable periods ended June 30, 2010 ascompared to 2009:

 
| ** **                              | ** ** | **Three Months Ended** | ** ** | **Six-Months Ended** | ** ** | **Twelve Months Ended** | ** ** |
|-----------------------------------------|------------|------------------------|------------|----------------------|------------|-------------------------|------------|
| Consolidated provision for income taxes |       | $0.4                   |       | $4.8                 |       | $0.7                    |       |

 

Thefollowing table shows our consolidated effective federal and state income taxrates for the applicable periods ended June 30, 2010:

 
| ** **                                                 | ** ** | **Three Months Ended** | ** ** | **Six Months Ended** | ** ** | **Twelve Months Ended** | ** ** |
|------------------------------------------------------------|------------|------------------------|------------|----------------------|------------|-------------------------|------------|
| ** **                                                 | ** ** | **2010**               | ** ** | **2009**             | ** ** | **2010**                | ** ** | **2009** | ** ** | **2010** | ** ** | **2009** | ** ** |
| Consolidated effective federal and state income  tax rates |       | 37.7%                  |       | 34.7%                |       | 47.5%                   |       | 34.2% |   | 38.9% |   | 33.5% |   |

 

The effective tax rates for the six months ended June 30, 2010 andthe twelve months ended June 30, 2010 are higher than comparable yearperiods primarily due to the new health care legislation. On March 23,2010, the Patient Protection and Affordable Care Act became law. Thislegislation includes a provision that reduces the deductibility, for income taxpurposes, 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 thelegislation is enacted. As a result, in the first quarter of 2010, we recordeda one-time non-cash charge of approximately $2.1 million to income taxes to 

 

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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.

 

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 in the first quarter of 2010. 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.

 

**Nonoperating Items**

 

The following table shows the total allowance forfunds used during construction (AFUDC) for the applicable periods ended June 30. AFUDC increased during all three periods in2010 as compared to the same periods in 2009 due to higher levels ofconstruction in each period.

 
| ** **                                             | ** ** | **Three Months Ended** | ** ** | **Six Months Ended** | ** ** | **Twelve Months Ended** | ** ** |
|--------------------------------------------------------|------------|------------------------|------------|----------------------|------------|-------------------------|------------|
| **($ in  millions)**                              | ** ** | **2010**               | ** ** | **2009**             | ** ** | **2010**                | ** ** | **2009** | ** ** | **2010** | ** ** | **2009** | ** ** |
| Allowance for equity funds used during  construction   |       | $                      | 1.9        |                 | $          | 1.2                     |       | $ | 3.7 |   | $ | 2.6 |   | $ | 7.2 |   | $ | 6.0 |   |
| Allowance for borrowed funds used during  construction |       | 2.4                    |       | 2.1                  |       | 4.8                     |       | 4.3 |   | 8.5 |   | 8.0 |   |
| Total AFUDC                                            |       | $                      | 4.3        |                 | $          | 3.3                     |       | $ | 8.5 |   | $ | 6.9 |   | $ | 15.7 |   | $ | 14.0 |   |

 

Totalinterest charges on long-term and short-term debt for the applicable periodsended June 30, are shown below. The decrease in long-term debt interestfor the quarter ended June 30, 2010 reflects the redemption of 61⁄2% firstmortgage bonds on April 1, 2010 which were replaced by 4.65% first mortgagebonds issued May 28, 2010. The increases in long-term debt interest forthe six-month ended and twelve-month ended periods reflect the interest on the$100 million principal amount of first mortgage bonds we issued May 28,2010 and the interest on the $75 million principal amount of first mortgagebonds we issued March 27, 2009. The decreases in short-term debt interestfor the six-month ended and twelve-month ended periods primarily reflect lowerlevels of borrowing.

 
| ** **                          | ** ** | **Interest Charges** | ** ** |
|-------------------------------------|------------|---------------------------|------------|
| ** **                          | ** ** | **(in millions)**    | ** ** |
| ** **                          | ** ** | **Second**                | ** ** | **Second** | ** ** | ** ** | ** ** | **6 Months** | ** ** | **6 Months** | ** ** | ** ** | ** ** | **12 Months** | ** ** | **12 Months** | ** ** | ** ** | ** ** |
| ** **                          | ** ** | **Quarter**               | ** ** | **Quarter** | ** ** | **%** | ** ** | **Ended** | ** ** | **Ended** | ** ** | **%** | ** ** | **Ended** | ** ** | **Ended** | ** ** | **%** | ** ** |
| ** **                          | ** ** | **2010**                  | ** ** | **2009** | ** ** | **Change*** | ** ** | **2010** | ** ** | **2009** | ** ** | **Change*** | ** ** | **2010** | ** ** | **2009** | ** ** | **Change*** | ** ** |
| Long-term debt interest             |       | 10.1                      |       | 10.9 |   | (7.6 | )% | 20.6 |   | 20.5 |   | 0.1 | % | 42.1 |   | 39.7 |   | 6.1 | % |
| Short-term debt interest            |       | 0.2                       |       | 0.2 |   | 18.6 |   | 0.5 |   | 0.8 |   | (37.7 | ) | 0.8 |   | 1.8 |   | (53.9 | ) |
| Trust preferred securities interest |       | 1.0                       |       | 1.1 |   | (3.3 | ) | 2.1 |   | 2.1 |   | (1.7 | ) | 4.2 |   | 4.2 |   | (0.8 | ) |
| Iatan1 carrying charges             |       | (0.6                      | )          | (0.6 | ) | (3.6 | ) | (1.2 | ) | (0.6 | ) | 92.3 |   | (1.9 | ) | (0.6 | ) | 210.7 |   |
| Other interest                      |       | 0.3                       |       | 0.1 |   | 42.5 |   | 0.4 |   | 0.3 |   | 46.5 |   | 0.8 |   | 0.9 |   | (10.2 | ) |
| Total interest charges              |       | 11.0                      |       | 11.7 |   | (6.2 | ) | 22.4 |   | 23.1 |   | (3.2 | ) | 46.0 |   | 46.0 |   | 0.1 |   |

 

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**Beginning in the second quarter of 2009, we deferred Iatan 1 carryingcharges in accordance with our agreement with the MPSC that allows deferral ofcertain costs until the environmental upgrades to Iatan 1 are included in ourrate base.*

** **

**RATE MATTERS**

 

Wecontinually assess the need for rate relief in all of the jurisdictions weserve and file for such relief when necessary.

 

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 of accumulated

 

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depreciationand regulatory amortization) of utility plant in service, subject to variousadjustments for deferred taxes and other items. Over time, rate base isincreased by additions to utility plant in service and reduced by depreciation,regulatory amortization and retirement of utility plant and write-off’s asordered by the utility commissions. In general, a request of new rates is madeon the basis of a “rate base” as of a date prior to the date of the request andallowable operating expenses for a 12-month test period ended prior to the dateof the request. Although the current rate making process provides recovery ofsome future changes in rate base and operating costs, it does not reflect allchanges in costs for the period in which new retail rates will be in place.This results in a lag between the time we incur costs and the time when we can startrecovering the costs through rates. See Note 3 of “Notes to ConsolidatedFinancial Statements” for the amounts recorded for regulatory amortization.

 

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

 
| **Jurisdiction**         | ** ** | **Date Requested**    | ** ** | **Annual Increase   Granted** | ** ** | **Percent   Increase   Granted** | ** ** | **Date Effective** | ** **           |
|--------------------------|------------|-----------------------|------------|-------------------------------|------------|----------------------------------|------------|--------------------|----------------------|
| Kansas – Electric   |       | November 4, 2009 |       | $                             | 2,800,000  |                             | 12.4%      |               | July 1, 2010    |   |
| Missouri – Gas      |       | June 5, 2009     |       | $                             | 2,600,000  |                             | 4.37%      |               | April 1, 2010   |   |
| Missouri – Electric |       | October 1, 2007  |       | $                             | 22,040,395 |                             | 6.70%      |               | 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 recovercapital expenditures associated with environmental upgrades at Iatan 1 and ourinvestment in new generating units at Iatan 2 and the Plum Point GeneratingStation. As a result of the delay in the Iatan 2 project, however, we agreed tonot seek 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 commonplant needed to operate Iatan 1. We anticipate filing a rate case at theconclusion of this case to recover the Iatan 2 costs.

 

Astipulated agreement was filed on May 12, 2010, calling for an annualincrease of $46.8 million, provided the Plum Point Generating Station meets itsin-service criteria by August 15, 2010. Should the in-service criteria notbe met, a base rate increase of $33.1 million is stipulated. The new rates areto be effective September 10, 2010. Both scenarios include incrementaladditional regulatory amortization in the amount of $10 million that will berecorded as depreciation expense. As of the date of this filing, we believethat we have met all but one Plum Point in-service criteria. The remaining testrequires that the unit operate at or above 80% of its design load for a continuous120 hour period with emission equipment operating effectively. Four hours ofthis test must be above 95% load. We currently estimate that this test willbegin on or before August 8, 2010. We anticipate filing a rate case at theconclusion of this case to recover the Plum Point costs if necessary. See Note7 of “Notes to Consolidated Financial Statements.” We have also agreed to theuse of construction accounting for our Plum Point project such as we use forour Iatan 2 project. However, construction accounting for Plum Point will notapply for up to 60 days between when Plum Point becomes fully operational andused for service and the date tariffs in this rate case become effective.Construction accounting 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. 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 in the first quarter of 2010. 

 

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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”.

 

*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.

 

Theorder contains two components. The first component provides an addition to baserates of approximately $27.7 million. This increase in base rates was partiallyoffset by a $5.7 million reduction to regulatory amortization, which is thesecond component to support certain credit metrics of the overall change inrevenue authorized by the MPSC. Regulatory amortization provides us additionalcash through rates during the current construction cycle. This construction,which is part of our long-range plan to ensure reliability, includes thefacilities at the Riverton Power Plant and Iatan 2 Power Plant, as well asenvironmental improvements at the Asbury Power Plant and at Iatan 1. Theregulatory amortization is now approximately $4.5 million annually and isrecorded as depreciation expense.

 

TheMPSC also authorized a fuel adjustment clause for our Missouri customerseffective September 1, 2008. The MPSC established a base cost for therecovery of fuel and purchased power expenses used to supply energy. The clausepermits the distribution to customers of 95% of the changes in fuel andpurchased power costs above or below the base cost. Off-system sales marginsare also part of the recovery of fuel and purchased power costs. As a result,the off-system sales margin flows back to the customer. Rates related to therecovery of fuel and purchased power costs will be modified twice a yearsubject to the review and approval by the MPSC. In accordance with accountingguidance for regulated activities, 95% of the difference between the actualcost of fuel and purchased power and the base cost of fuel and purchased powerrecovered from our customers is recorded as an adjustment to fuel and purchasedpower expense with a corresponding regulatory asset or a regulatory liability.If the actual fuel and purchased power costs are higher or lower than the basefuel and purchased power costs billed to customers, 95% of these amounts willbe recovered or refunded to our customers when the fuel adjustment clause ismodified. On April 1, 2009, we filed proposed rate schedules with the MPSCrequesting an increase of $1.9 million in revenues for the under recovered fuelcosts recognized for the six month period ended February 28, 2009. Thisincrease in revenue was approved by the MPSC on May 21, 2009, becameeffective June 1, 2009 and is billed through our fuel adjustment clause.On October 1, 2009, we filed proposed rate schedules with the MPSCrequesting a decrease of $0.8 million in revenues for the over recovered fueland purchased power costs recognized for the six month period ended August 31,2009.

 

TheMPSC order in the rate case approved a Stipulation and Agreement providing forthe recovery of deferred expenses of approximately $14.2 million over a fiveyear period for the 2007 ice storms. In addition, the MPSC order required theimplementation of a two-way tracking mechanism for recovery of the costsrelating to the new MPSC rules on infrastructure inspection and vegetationmanagement. The mechanism authorized by the MPSC creates a regulatory liabilityin any year we spend less than the target amount, which has been set at $8.6million for our Missouri jurisdiction, and a regulatory asset if we spend morethan the target amount. Any regulatory asset and liability amounts createdusing the tracking mechanism will then be netted against each other and takeninto account in our next rate case. The MPSC also approved Stipulations andAgreements providing for the continuation of the pension and otherpost-retirement employee benefits tracking mechanism established in our 2006and 2007 Missouri rate 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 

 

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approvedour tariff sheets containing our base rates for service rendered on and after August 23,2008, and approved our fuel adjustment clause tariff sheets effective September 1,2008. On September 3, 2008, theMPSC denied all pending applications 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 Western District Court of Appeals.

 

*2006 Rate Case*

 

In December 2008, the OPC andintervenors Praxair, 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 June 2, 2009. The Cole County Circuit Courtissued a ruling on December 8, 2009, affirming the Commission’s Report andOrder. OPC, Praxair and Explorer Pipeline have filed appeals with the WesternDistrict 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 was 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. A stipulated agreement was filed on May 4,2010, and approved by the KCC on June 25, 2010, calling for a $2.8million, or 12.4%, increase in base rates effective July 1, 2010. We willdefer depreciation and operating and maintenance expense on both Plum Point andIatan 2 from their respective in-service dates until the effective date forrates from the next Kansas case, expected to be an abbreviated rate case thatwill be filed within the next year. These deferrals will be recovered over a3-5 year period as determined in that next case. We will record AFUDC on allPlum Point and Iatan 2 capital expenditures incurred after January 31,2010.

 

*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, or approximately 33%.

 

*Arkansas*

 

OnJune 1, 2010, we advised the Arkansas Public Service Commission of theintention to file an application for a general change or modification in ourrates, charges and tariffs no sooner than 60 days and no later than 90 daysfrom the date of notice.

 

*FERC*

 

OnMarch 12, 2010, we filed GFR tariffs with the FERC which we propose to beutilized for our wholesale customers. On May 28, 2010, the FERC issued anorder that conditionally approved our GFR filing subject to refund effective June 1,2010. On June 30, 2010, three of our on-system wholesale customers weregranted intervention in the GFR rate case. Also on May 28, 2010, we fileda notice with the FERC requesting termination of the current bundled serviceagreements for our wholesale customers effective July 31, 2010. On July 28,2010, the FERC issued an order accepting and suspending the proposedterminations for a nominal period to become effective July 31, 2010,subject to refund. The FERC’s order also consolidated the GFR and terminationproceedings.

 

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***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 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 Empire for anincrease of $2.6 million. Pursuant to the Agreement, new rates went into effecton April 1, 2010.

 

**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 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 our customersyet expect our 

 

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shareof the net allocated costs to be immaterial. Also on April 28, 2009, theSPP RSC and BOD approved a new report that recommended restructuring of the SPP’sregional planning processes, which would establish an integrated planningprocess for reliability, transmission service and economic transmissionprojects, based on a new set of planning principles that focus on theconstruction of a more robust transmission system large enough in both scaleand geography to provide flexibility to meet SPP members’ and customers’ futureneeds. We will continue to actively participate in the development of these newprocesses as well as cost allocation and recovery issues with members,prospective customers and the state commission representatives to the SPP RSC.

 

On October 27, 2009, the SPP BOD endorsed a new transmission costallocation method to replace the existing FERC accepted cost allocation methodfor new transmission facilities needed to continue to reliably and economicallyserve SPP customers, including ours, well into the future. On April 19,2010, SPP filed revisions to its OATT to adopt a new highway/byway costallocation methodology which require SPP BOD approved transmission projects of300 kV or larger to be funded by the region at 100%, transmission projectsbetween 100 kV and 300 kV to receive 33% regional funding with individual constructingzones to pay 67% of those projects built within the zone. For projects under100kV, the constructing zones would pay 100% of the cost. On May 17, 2010,we filed a joint protest at the FERC with other SPP members based on ourdisagreement with the SPP on the allocation percentages and various otherissues. On June 17, 2010, the FERC unconditionally approved the newhighway/byway cost allocation method. We and other members of the SPP filed aRequest for Rehearing on July 19, 2010. It is uncertain as to when theFERC will rule on our Request for Rehearing. On May 17, 2010, in arelated but separate filing, the SPP filed revisions to its OATT to incorporatea modified transmission planning process, the Integrated Transmission Plan(ITP) that the SPP will use to determine it’s near and long term transmissionneeds to meet reliability and provide economic benefits throughout the SPPregion. On June 7, 2010, we made a joint protest filing at the FERCregarding the ITP filing which expressed our concerns over the lack of explicitprovisions in the SPP OATT to protect SPP customers from the approval oftransmission projects that may not sufficiently benefit the SPP region. On July 15,2010, the FERC issued an order conditionally accepting SPP proposed ITP planningprocess and tariff provisions to be effective on July 17, 2010 and orderedSPP to make a compliance filing by August 15, 2010 on the timing of ITPbusiness practices and factors to be considered for changing the allocation ofcosts methods for dual winding high voltage transformers. We and the otherparties to the SPP ITP joint filing plan to file a formal Request for Rehearingat the FERC on the ITP order by August 15, 2010.

 

*FERC Market Power Order*

 

Aspart of our market based pricing authority from the FERC, we are required toconduct a market power analysis within our service territory and within the SPPRTO region every three years. We filed our triennial market power analysis withthe FERC on July 30, 2009, concluding there were no material changes toour market position. As a result, we did not anticipate any changes to ourexisting market based rate authority. On July 13, 2010, the FERC issued anorder accepting our triennial market power analysis and authorized thecontinuation of our market based rate authority for wholesale transactionsoutside our service territory.

 

*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 

 

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customers.We continue to be involved in the SPP RTO and our state commission discussionson 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 the basis on which a public utility’s waiver waspremised. The Standards of Conduct generally govern the communications betweenour day to day transmission operations personnel and our day to day wholesalemarketing and sales personnel. We submitted our filing on July 13, 2009 inwhich we stated our belief that continuation of our waiver, issued in 1997 andreaffirmed in 2004, was appropriate and reasonable. Based on the May 21,2009 order, it is possible that the FERC will revoke our waiver which wouldimpact communication between our transmission and wholesale marketing and salesfunctions and operations within our organization. As part of our filing, wesought a twelve month extension in order to comply with the Standard of Conductrequirements in the event the FERC determined that revoking our waiver wasappropriate. The FERC’s decision on this and other Standard of Conduct waiverfilings is pending. As of July 19, 2010, we have voluntarily taken stepsto allow us to comply with a FERC order with minimal additional impact.

 

***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 CAPITAL RESOURCES**

 

***Overview.    **** *Our primarysources of liquidity are cash provided by operating activities, short-termborrowings under 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.

 

Ourissuance of various securities, including equity, long-term and short-termdebt, is subject to customary approval or authorization by state and federalregulatory bodies including state public service commissions and the SEC. Weestimate that internally generated funds (funds provided by operatingactivities less dividends paid) will provide only a portion of the fundsrequired in 2010 for our budgeted capital expenditures (as discussed in “CapitalRequirements and Investing Activities” below). Although our working capital wasnegative as of June 30, 2010, we believe the amounts available to us underour credit facilities and the issuance of debt and equity securities togetherwith this cash provided by operating activities will allow us to meet our needsfor working capital, pension contributions, our continuing constructionexpenditures, anticipated debt redemptions, interest payments on debtobligations, dividend payments and other cash needs through the next severalyears.

 

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 periods shown below:

 

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**Summaryof Cash Flows**

 
| ** **                              | ** ** | **Six Months Ended June 30,** | ** ** |
|-----------------------------------------|------------|------------------------------------|------------|
| **(in  millions)**                      | ** ** | **2010**                           | ** ** | **2009** | ** ** |
| Cash provided by (used in):             |       |                               |       |   |   |
| Operating activities                    |       | $                                  | 42.0       |   | $ | 60.0 |   |
| Investing activities                    |       | (59.2                              | )          | (84.0 | ) |
| Financing activities                    |       | 18.3                               |       | 24.6 |   |
| Net change in cash and cash equivalents |       | $                                  | 1.1        |   | $ | 0.6 |   |

 

**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 that impact net income but may not resultin actual cash receipts or payments during the period. These reconciling itemsinclude depreciation and amortization, pension costs, deferred income taxes,equity AFUDC, changes in commodity risk management assets and liabilities andchanges in the consolidated balance sheet for working capital from thebeginning 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.

 

*SixMonths Ended June 30, 2010 Compared to 2009**. *During the six months ended June 30,2010, our net cash flow provided from operating activities was $42.0 million, adecrease of $18.0 million or 30.0% from 2009. This decrease was primarily aresult of:

 

·                  Changes in net income - $(2.6) million.

·                  Draw down of the commodity risk managementmargin accounts through settlement of hedged positions in 2009 - $(5.4)million.

·                  Changes in seasonal levels of inventory,including the effect of building coal inventories at Plum Point and Iatan 2 -$(9.7) million.

·                  Changes in prepaid expenses and deferredcharges primarily related to deferred fuel costs and increased bank fees -$(2.8) million.

·                  Changes in accrued fuel and constructionliabilities - $2.7 million

** **

**CapitalRequirements and Investing Activities**

 

Ournet cash flows used in investing activities decreased $24.7 million during thesix months ended June 30, 2010 as compared to the same period in 2009.

 

Our capital expenditures incurred totaled approximately $56.6 millionduring the six months ended June 30, 2010 compared to $82.3 million forthe six months ended June 30, 2009. The decrease was primarily the resultof a decrease in electric plant additions and replacements, storm expendituresand new generation construction in 2010.

 

A breakdown of the capital expenditures for the six months ended June 30,2010 and 2009 is as follows:

 

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| ** **                                                   | ** ** | **Capital Expenditures** | ** ** |
|--------------------------------------------------------------|------------|--------------------------|------------|
| **(in  millions)**                                           | ** ** | **2010**                 | ** ** | **2009** | ** ** |
| Distribution and transmission system additions               |       | $                        | 16.0       |   | $ | 17.2 |   |
| New Generation — Plum Point Energy Station              |       | 5.3                      |       | 9.0 |   |
| New Generation — Iatan 2                                |       | 30.6                     |       | 31.5 |   |
| Storms                                                       |       | —                   |       | 6.3 |   |
| Additions and replacements — electric plant             |       | 2.9                      |       | 17.5 |   |
| Gas segment additions and replacements                       |       | 0.8                      |       | 0.8 |   |
| Transportation                                               |       | 0.8                      |       | 0.8 |   |
| Other (including retirements and salvage -net) (1)           |       | (1.8                     | )          | (1.6 | ) |
| **Subtotal**                                                 |       | 54.6                     |       | 81.5 |   |
| Non-regulated capital expenditures (primarily  fiber optics) |       | 2.0                      |       | 0.8 |   |
| **Subtotal capital expenditures  incurred (2)**              |       | 56.6                     |       | 82.3 |   |
| Adjusted for capital expenditures payable (3)                |       | 2.6                      |       | 2.2 |   |
| **Total cash outlay**                                        |       | $                        | 59.2       |   | $ | 84.5 |   |

 

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(1) Otherincludes equity AFUDC of $(3.7) million and $(2.6) million for 2010 and 2009,respectively.

(2) Expenditures incurred represent the total cost for workcompleted for the projects during the reporting period. Discussion of capitalexpenditures throughout this 10-Q is presented on this basis. These capitalexpenditures include AFUDC, capital expenditures to retire assets and benefitsfrom salvage.

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

 

Noneof our cash requirements for capital expenditures during the second quarter of2010 were satisfied internally from operations (funds provided by operatingactivities less dividends paid). The amounts of such requirements weresatisfied from short-term borrowings and proceeds from our sales of commonstock and debt securities discussed below.

 

Weestimate that internally generated funds will provide approximately 93% 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 ourEmployee Stock Purchase Plan, our Dividend Reinvestment and Stock PurchasePlan, and our 401(k) Plan and ESOP) to finance additional amounts neededbeyond those provided by operating activities for such capital expenditures. Wewill continue to utilize short-term debt as needed to support normal operationsor other temporary requirements. For further information see Note 6 of “Notesto Consolidated Financial Statements (Unaudited).”

 

**FinancingActivities**

 

Ournet cash flows provided by financing activities decreased $6.3 million duringthe first six months of 2010 as compared to the same period in 2009.

 

OnJuly 26, 2010, we issued a notice to call all $48.3 million aggregateprincipal amount of our Senior Notes, 7.05% Series due 2022 for redemptionon August 27, 2010. We expect to finance the redemption with an offeringof first mortgage bonds. The redemption is conditioned upon the consummation ofthis offering. If we are unable to complete this offering, the notice ofredemption would be of no effect unless we waive this condition.

 

OnMay 28, 2010, we issued $100 million principal amount of 4.65% firstmortgage bonds due June 1, 2020. The net proceeds (after payment ofexpenses) of approximately $98.9million, were used to redeem all 2 million outstanding shares of our 8.5%trust preferred securities, totaling $50 million, on June 28, 2010 and torepay short-term debt which was incurred, in part, to fund the repayment, atmaturity, of our 6.5% first mortgage bonds due 2010.

 

Wesuccessfully completed our equity distribution program during the secondquarter of 2010 and used the net proceeds to repay short-term debt and forgeneral corporate purposes, including the funding of our current constructionprogram. During the second quarter of 2010, we issued and sold 1,192,644 sharesof our common stock pursuant to this equity distribution program, at an averageprice per share of $18.60, resulting in net proceeds to us of approximately$21.5 million (after payment of approximately $0.7 million in commissions tothe sales agent). Since inception of the program, in the aggregate, we issuedand sold 6,535,216 shares pursuant to the 

 

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program,at an average price per share of $18.36, resulting in net proceeds to us ofapproximately $116.0 million. See Note 6 of “Notes to Consolidated FinancialStatements (Unaudited)” for additional information regarding our equitydistribution program.

 

Wehad $40 million in short-term debt as of June 30, 2010 versus $72 millionas of June 30, 2009.

 

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 June 30, 2010, $105 million remains available forissuance under this shelf registration statement. Of the original $400 million,$250 million was available for first mortgage bonds with $75 million remainingavailable after the issuance of $100 million in first mortgage bonds on May 28,2010 and $75 million in first mortgage bonds on March 27, 2009. We plan touse a portion of the proceeds from issuances under this shelf to fund a portionof the capital expenditures for our new generation projects and to refinancelong-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 reduced over a fouryear period in line with the amount of construction expenditures we owed forPlum Point Unit 1 and terminated on July 15, 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 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 therevolving commitments remained unchanged at $150 million and there were noother material changes to the terms of the facility. The facility is used forworking 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 June 30, 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 were no outstanding borrowings under this agreement at June 30,2010. However, $40.0 million was used to back up our outstanding commercialpaper.

 

OnMarch 11, 2009, we entered into a $50 million unsecured credit agreement.This agreement, which terminated on July 15, 2010, provided for $50million of revolving loans to be available to us for working capital, generalcorporate purposes and to back-up our use of 

 

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commercialpaper and was in addition to, and had substantially identical covenants andterms as (other than pricing) our Second Amended and Restated Unsecured CreditAgreement dated January 26, 2010 discussed above. At June 30, 2010,there were no borrowings under this agreement.

 

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 in the EDE mortgage bondindenture could affect our liquidity. The EDE Mortgage contains a requirementthat for new first mortgage bonds to be issued, our net earnings (as defined inthe EDE Mortgage) for any twelve consecutive months within the fifteen monthspreceding issuance must be two times the annual interest requirements (asdefined in the EDE Mortgage) on all first mortgage bonds then outstanding andon the prospective issue of new first mortgage bonds. Our earnings for thetwelve months ended June 30, 2010 would permit us to issue approximately$288.7 million of new first mortgage bonds based on this test with an assumedinterest rate of 6.0%. In addition to the interest coverage requirement, theEDE Mortgage provides that new bonds must be issued against, among other things,retired bonds or 60% of net property additions. At June 30, 2010, we hadretired bonds and net property additions which would enable the issuance of atleast $613.2 million principal amount of bonds if the annual interestrequirements are met. As of June 30, 2010, we are in compliance with allrestrictive 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 suchissuance, EDG’s ratio of EBITDA (defined as net income plus interest, taxes,depreciation, amortization and certain other non-cash charges) to interestcharges for the most recent four fiscal quarters is at least 2.0 to 1.****As of June 30, 2010, this test would allow us to issueapproximately $5.2 million principal amount of new first mortgage bonds.

 

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

 
| ** **               | ** ** | **Fitch** | ** ** | **Moody’s** | ** ** | **Standard & Poor’s** |
|--------------------------|------------|-----------|------------|------------------|------------|-------------------------------------|
| Corporate  Credit Rating |       | n/r*      |       | Baa2             |       | BBB-                                |
| First  Mortgage Bonds    |       | BBB+      |       | A3               |       | BBB+                                |
| Senior  Notes            |       | BBB       |       | Baa2             |       | BBB-                                |
| Commercial  Paper        |       | F2        |       | P-2              |       | A-3                                 |
| Outlook                  |       | Stable    |       | Stable           |       | 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 14, 2010, Moody’s upgraded our First Mortgage Bonds from Baa1 to A3and upgraded its outlook from negative to stable. Moody’s affirmed all of ourother ratings. On April 1, 2010, Fitch affirmed our ratings and revisedtheir rating outlook to stable. The revision took into consideration theanticipated completion of our five-year baseload capital expenditure program in2010 and assumes we will receive timely and adequate regulatory recovery ofnewly completed investments.

 

Asecurity rating is not a recommendation to buy, sell or hold securities. Eachrating is subject to revision or withdrawal at any time by the assigning ratingorganization. Each security rating agency has its own methodology for assigningratings, and, accordingly, each rating should be considered independently ofall other ratings.

 

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**CONTRACTUAL OBLIGATIONS**

 

Materialchanges to our contractual obligations at June 30, 2010, compared to December 31,2009 consist of the following. We issued $100 million principal amount of 4.65%first mortgage bonds on May 28, 2010 which are due June 1, 2020 andrequire semi-annual interest payments of $2.3 million. Funds from this offeringwere used in part to refinance $50 million of 8.5% Trust Preferred Securitieson June 28, 2010 that were originally due 2031 and required quarterlyinterest payments totaling $4.3 million each year. The proceeds were also usedto repay short-term debt which was incurred, in part, to fund the repayment of$50 million of 6.5% first mortgage bonds which matured April 1, 2010. Wealso entered into a contract in the second quarter of 2010 for thetransportation of coal beginning June 30, 2010, which replaced a contractthat expired June 29, 2010. The contract term is for six and one-half yearsand the minimum payments total approximately $91.9 million over the term of thecontract. Minimum payments under this contract are as follows:  2010 - $7.9 million; 2011-2012 - $28.0million; 2013-2014 - $28.0 million; and 2015 and thereafter - $28.0 million.

 

**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 and preferencestock. Payment of dividends is determined by our Board of Directors afterconsidering all relevant factors, including the amount of our retained earnings(which is essentially our accumulated net income less dividend payouts). As of June 30,2010 our retained earnings balance was $0.6 million, compared to $10.3 millionas of June 30, 2009, after paying out $13.1 million in dividends duringthe second quarter of 2010. A reduction of our dividend per share, partially orin whole, could have an adverse effect on our common stock price. On July 29,2010, the Board of Directors declared a quarterly dividend of $0.32 per shareon common stock payable September 15, 2010 to holders of record as of September 1,2010.

 

Our diluted earnings pershare were $0.40 for the six months ended June 30, 2010 and were $1.18 and$1.17 for the years ended December 31, 2009 and 2008, respectively.Dividends paid per share were $0.64 for the six months ended June 30, 2010and $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 determination would be based on a fact-intensiveanalysis of the specific facts and circumstances surrounding the utility andthe dividend in question, with particular focus on the impact of the proposeddividend on the liquidity and financial 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 stockfinancing) any shares of, our common stock if the cumulative aggregate amountthereof after August 31, 1944 (exclusive of the first quarterly dividendof $98,000 paid after said date) would exceed the sum of $10.75 million and theearned surplus (as defined in the EDE Mortgage) accumulated subsequent to August 31,1944, or the date of succession in the event that another corporation succeedsto our rights and liabilities by a merger or consolidation. On March 11, 2008,

 

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weamended the EDE Mortgage in order to provide us with more flexibility to paydividends to our shareholders by increasing the basket available to paydividends by $10.75 million, as described above. As of June 30, 2010, thisrestriction did not prevent us from issuing 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 — Management’s 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 June 30, 2010.

** **

**RECENTLY ISSUED ACCOUNTING STANDARDS**

 

SeeNote 2 of “Notes to Consolidated Financial Statements (Unaudited)”.

 

**Item 3.  Quantitative andQualitative Disclosures about 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 thepotential adverse financial impact related to changes in interest rates.

 

*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.Derivatives are utilized to manage our gas commodity market risk and to helpmanage our exposure resulting from purchasing most of our natural gas on thevolatile spot market for the generation of power for our native-load customers.See Note 4 of “Notes to Consolidated Financial Statements (Unaudited)” forfurther information.

 

*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.

 

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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 July 23, 2010, 80%, or 2.8 million Dths, of ouranticipated volume of natural gas usage for our electric operations for theremainder of 2010 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 June 30, 2010, our natural gas cost would increase byapproximately $1.4 million based on our June 30 2010 total hedgedpositions for the next twelve months. However, this is probable of recoverythrough fuel adjustment mechanisms. We have a fuel cost recovery mechanism inall of our jurisdictions, which significantly reduces the impact of fluctuatingfuel 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 June 30, 2010, we have 1.0 million Dths in storage on thethree pipelines that serve our customers. This represents 52% of our storagecapacity. We have an additional 0.4 million Dths hedged through financialderivative and physical contracts. Ourlong-term hedge strategy is to mitigate price volatility for our customers byhedging a minimum of 50% of the current year, up to 50% of the second year andup to 20% of third year expected gas usage by the beginning of the ACA year at September 1. However, dueto purchased natural gas cost recovery mechanisms for our retail customers,fluctuations in the cost of natural gas have little effect on income.

 

*CreditRisk*.

 

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, certain counterparties make available collateral in the form ofcash held as margin deposits as a result of exceeding agreed-upon creditexposure thresholds or may be required to prepay the transaction. Conversely,we are required to post collateral with counterparties at certain thresholds,which is typically the result of changes in commodity prices. Amounts reportedas margin deposit liabilities represent counterparty funds we hold that resultfrom various 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 financialcontracts with other counterparties that resulted from us exceeding agreed-uponcredit limits established by the counterparties. The following table depictsour margin deposit assets at June 30, 2010 and December 31, 2009.There were no margin deposit liabilities at these dates.

 
| **(in millions)** | ** ** | **June 30, 2010** | ** ** | **December 31, 2009** | ** ** |
|------------------------|------------|-----------------------------|------------|---------------------------------|------------|
|                   |       |                        |       |                            |       |
| Margin deposit assets  |       | $                           | 3.1        |                            | $          | 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 June 30,2010, 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 |       | $          | 15.1       |   |
| Net unrealized mark-to-market losses for financial  natural gas contracts        |       | 3.7        |       |
| **Net credit exposure**                                                          | ** ** | **$**      | **18.8**   | ** ** |

 

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The$3.7 million net unrealized mark-to-market loss for financial natural gascontracts is comprised of $4.1 million that our counterparties are exposed toEmpire for unrealized losses and $0.4 million of unrealized gains from ourcounterparties. We are holding no collateral from any counterparty since we arebelow the $10 million mark-to-market collateral threshold in our agreements. Asnoted above, as of June 30, 2010, we have $3.1 million on deposit forNYMEX contract exposure to Empire, of which $3.0 million represents ourcollateral requirement. In addition, ifNYMEX gas prices decreased 25% from their June 30, 2010 levels, we wouldbe required to post an additional $2.9 million in collateral. If these pricesincreased 25%, our collateral requirement would decrease $2.6 million. Ourother counterparties would not be required to post collateral 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, weenter into contracts with various companies in the energy industry forpurchases of energy-related commodities, including natural gas in our fuelprocurement process.

 

*Interest Rate Risk.*

 

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.

 

**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 ChiefFinancial Officer concluded that our disclosure controls and procedures wereeffective as of June 30, 2010.

 

There have been no changes in our internal control over financialreporting that occurred during the second 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 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.

 

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** **

**Item 1A.  Risk Factors.**

 

There have been no material changes to the factors disclosed in Part I, Item1-A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31,2009.

** **

**Item5.  Other Information.**

 

Forthe twelve months ended June 30, 2010, our ratio of earnings to fixedcharges was 2.23x.  See Exhibit (12)hereto.

 

**Item 6.  Exhibits.**

 

(a)                                  Exhibits.

 

(4) Thirty-FifthSupplemental Indenture, dated as of May 28, 2010, to the Indenture ofMortgage and Deed of Trust dated as of September 1, 1944, as amended andsupplemented, among the Company, The Bank of New York Mellon Trust Company,N.A. and UMB Bank & Trust, N.A. (Incorporated by reference to Exhibit 4.1to Current Report on Form 8-K dated May 28, 2010 and filed May 28,2010, File No. 1-3368).

 

(12)Computation of Ratio of Earnings 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 |
|                 |                                      |
| August 5,  2010 |                                      |

 

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