Table of Contents

 

 

 

**UNITED STATES**

**SECURITIES 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, 2009**

 

**or**

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

 

**For the transition periodfrom                    to                    .**

 

**Commission file number: 1-3368**

 

**THE EMPIRE DISTRICT ELECTRICCOMPANY**

(Exact name of registrant as specified in its charter)

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

As of August 1,2009, 34,492,377 shares of common stock were outstanding.

 

 

 

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**THEEMPIRE DISTRICT ELECTRIC COMPANY**

 

**INDEX**

 
| ** **    | ** **                                                                                  | **PAGE** |
|---------------|---------------------------------------------------------------------------------------------|----------|
|          | Forward Looking Statements                                                                  | 3        |
|          |                                                                                        |     |
| Part I - | Financial Information:                                                                      |     |
|          |                                                                                        |     |
| Item 1.       | Financial Statements:                                                                       |     |
|          |                                                                                        |     |
|          | a.     Consolidated Statements of Operations                            | 4        |
|          |                                                                                        |     |   |
|          | b.     Consolidated Statements of Comprehensive  Income                 | 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 | 34       |
|          |                                                                                        |     |
|          | Executive  Summary                                                                          | 34       |
|          |                                                                                        |     |
|          | Results  of Operations                                                                      | 37       |
|          |                                                                                        |     |
|          | Rate  Matters                                                                               | 49       |
|          |                                                                                        |     |
|          | Competition                                                                                 | 51       |
|          |                                                                                        |     |
|          | Liquidity and Capital Resources                                                             | 53       |
|          |                                                                                        |     |
|          | Contractual  Obligations                                                                    | 56       |
|          |                                                                                        |     |
|          | Dividends                                                                                   | 56       |
|          |                                                                                        |     |
|          | Off-Balance Sheet Arrangements                                                              | 57       |
|          |                                                                                        |     |
|          | Critical Accounting Policies                                                                | 57       |
|          |                                                                                        |     |
|          | Recently Issued Accounting Standards                                                        | 58       |
|          |                                                                                        |     |
| Item 3.       | Quantitative  and Qualitative Disclosures About Market Risk                                 | 58       |
|          |                                                                                        |     |
| Item 4.       | Controls and  Procedures                                                                    | 60       |
|          |                                                                                        |     |
| Part II- | Other Information:                                                                          |     |
|          |                                                                                        |     |
| Item 1.       | Legal Proceedings                                                                           | 60       |
|          |                                                                                        |     |
| Item 1A.      | Risk Factors                                                                                | 60       |
|          |                                                                                        |     |
| Item  2.      | Unregistered  Sales of Equity Securities and Use of Proceeds - (none)                       |     |
|          |                                                                                        |     |
| Item  3.      | Defaults  Upon Senior Securities - (none)                                                   |     |
|          |                                                                                        |     |
| Item 4.       | Submission  of Matters to a Vote of Security Holders                                        | 64       |
|          |                                                                                        |     |
| Item 5.       | Other Information                                                                           | 65       |
|          |                                                                                        |     |
| Item 6.       | Exhibits                                                                                    | 65       |
|          |                                                                                        |     |
|          | Signatures                                                                                  | 66       |

 

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**FORWARD LOOKING STATEMENTS**

 

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

 

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

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

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

·                  the results of prudency and similarreviews by regulators of costs we incur;

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

·                  operation of our electric generation facilitiesand electric and gas transmission and distribution systems, including theperformance of our joint owners;

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

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

·                  legislation;

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

·                  competition, including the regional SPPenergy imbalance market;

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

·                  the impact of electric deregulation onoff-system sales;

·                  changes in accounting requirements;

·                  other circumstances affecting anticipatedrates, revenues and costs;

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

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

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

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

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

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

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

·                  our exposure to the credit risk of ourhedging counterparties.

 

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

 

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

 

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**PART I.  FINANCIAL INFORMATION**

 

**Item 1.  FinancialStatements**

 

**THEEMPIRE DISTRICT ELECTRIC COMPANY**

**CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)**

 
| ** **                                                                              | ** ** | **Three Months Ended**                     | ** **  |
|-----------------------------------------------------------------------------------------|------------|--------------------------------------------|-------------|
| ** **                                                                              | ** ** | **June 30**                           | ** **  |
| ** **                                                                              | ** ** | **2009**                                   | ** **  | **2008** | ** ** |
| ** **                                                                              | ** ** | **(000’s except per share  amounts)** | ** **  |
| **Operating revenues:**                                                                 | ** ** | ** **                                 |        |   |   |
| Electric                                                                                | ** ** | **$**                                      | **102,649** |   | $ | 100,502 |   |
| Gas                                                                                     | ** ** | **7,919**                                  |        | 9,148 |   |
| Water                                                                                   | ** ** | **434**                                    |        | 441 |   |
| Other                                                                                   | ** ** | **1,228**                                  |        | 1,189 |   |
|                                                                                    | ** ** | **112,230**                                |        | 111,280 |   |
| **Operating revenue deductions:**                                                       | ** ** | ** **                                 |        |   |   |
| Fuel  and purchased power                                                               | ** ** | **41,548**                                 |        | 46,942 |   |
| Cost  of natural gas sold and transported                                               | ** ** | **4,211**                                  |        | 5,297 |   |
| Regulated  operating expenses                                                           | ** ** | **18,076**                                 |        | 17,663 |   |
| Other  operating expenses                                                               | ** ** | **422**                                    |        | 443 |   |
| Maintenance  and repairs                                                                | ** ** | **8,925**                                  |        | 6,827 |   |
| Depreciation  and amortization                                                          | ** ** | **12,739**                                 |        | 13,862 |   |
| Provision  for income taxes                                                             | ** ** | **4,028**                                  |        | 1,972 |   |
| Other  taxes                                                                            | ** ** | **6,254**                                  |        | 5,948 |   |
|                                                                                    | ** ** | **96,203**                                 |        | 98,954 |   |
|                                                                                    | ** ** | ** **                                 |        |   |   |
| **Operating income**                                                                    | ** ** | **16,027**                                 |        | 12,326 |   |
| **Other income and (deductions):**                                                      | ** ** | ** **                                 |        |   |   |
| Allowance  for equity funds used during construction                                    | ** ** | **1,229**                                  |        | 1,497 |   |
| Interest  income                                                                        | ** ** | **61**                                     |        | 543 |   |
| Provision  for other income taxes                                                       | ** ** | **(19**                                    | **)**       | (282 | ) |
| Other,  net                                                                             | ** ** | **(43**                                    | **)**       | (224 | ) |
|                                                                                    | ** ** | **1,228**                                  |        | 1,534 |   |
| **Interest charges:**                                                                   | ** ** | ** **                                 |        |   |   |
| Long-term  debt                                                                         | ** ** | **10,912**                                 |        | 8,838 |   |
| Note  payable to securitization trust                                                   | ** ** | **1,062**                                  |        | 1,062 |   |
| Short-term  debt                                                                        | ** ** | **206**                                    |        | 312 |   |
| Allowance  for borrowed funds used during construction                                  | ** ** | **(2,106**                                 | **)**       | (1,514 | ) |
| Other                                                                                   | ** ** | **(446**                                   | **)**       | 345 |   |
|                                                                                    | ** ** | **9,628**                                  |        | 9,043 |   |
| ** **                                                                              | ** ** | ** **                                 |        |   |   |
| **Net income**                                                                          | ** ** | **$**                                      | **7,627**   |   | $ | 4,817 |   |
| ** **                                                                              | ** ** | ** **                                 |        |   |   |
| Weighted  average number of common shares outstanding - basic                           | ** ** | **34,194**                                 |        | 33,775 |   |
|                                                                                    | ** ** | ** **                                 |        |   |   |
| Weighted  average number of common shares outstanding - diluted                         | ** ** | **34,223**                                 |        | 33,807 |   |
|                                                                                    | ** ** | ** **                                 |        |   |   |
| **Total earnings per weighted average share of  common stock – basic and diluted** | ** ** | **$**                                      | **0.22**    |   | $ | 0.14 |   |
| ** **                                                                              | ** ** | ** **                                 |        |   |   |
| **Dividends per share of common stock**                                                 | ** ** | **$**                                      | **0.32**    |   | $ | 0.32 |   |

 

*See accompanying Notes to Consolidated Financial Statements.*

 

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**THEEMPIRE DISTRICT ELECTRIC COMPANY**

**CONSOLIDATEDSTATEMENTS OF OPERATIONS (UNAUDITED)**

 
| ** **                                                                              | ** ** | **Six Months Ended**                       | ** **  |
|-----------------------------------------------------------------------------------------|------------|--------------------------------------------|-------------|
| ** **                                                                              | ** ** | **June 30,**                          | ** **  |
| ** **                                                                              | ** ** | **2009**                                   | ** **  | **2008** | ** ** |
| ** **                                                                              | ** ** | **(000’s except per share  amounts)** | ** **  |
| **Operating revenues:**                                                                 | ** ** | ** **                                 |        |   |   |
| Electric                                                                                | ** ** | **$**                                      | **209,011** |   | $ | 208,806 |   |
| Gas                                                                                     | ** ** | **36,006**                                 |        | 36,424 |   |
| Water                                                                                   | ** ** | **859**                                    |        | 876 |   |
| Other                                                                                   | ** ** | **2,369**                                  |        | 2,119 |   |
|                                                                                    | ** ** | **248,245**                                |        | 248,225 |   |
| **Operating revenue deductions:**                                                       | ** ** | ** **                                 |        |   |   |
| Fuel  and purchased power                                                               | ** ** | **88,338**                                 |        | 103,884 |   |
| Cost  of natural gas sold and transported                                               | ** ** | **23,519**                                 |        | 22,998 |   |
| Regulated  operating expenses                                                           | ** ** | **35,577**                                 |        | 35,561 |   |
| Other  operating expenses                                                               | ** ** | **831**                                    |        | 826 |   |
| Maintenance  and repairs                                                                | ** ** | **16,592**                                 |        | 12,393 |   |
| Depreciation  and amortization                                                          | ** ** | **25,412**                                 |        | 27,483 |   |
| Provision  for income taxes                                                             | ** ** | **9,561**                                  |        | 5,089 |   |
| Other  taxes                                                                            | ** ** | **13,733**                                 |        | 13,106 |   |
|                                                                                    | ** ** | **213,563**                                |        | 221,340 |   |
|                                                                                    | ** ** | ** **                                 |        |   |   |
| **Operating income**                                                                    | ** ** | **34,682**                                 |        | 26,885 |   |
| **Other income and (deductions):**                                                      | ** ** | ** **                                 |        |   |   |
| Allowance  for equity funds used during construction                                    | ** ** | **2,636**                                  |        | 2,615 |   |
| Interest  income                                                                        | ** ** | **137**                                    |        | 623 |   |
| Provision  for other income taxes                                                       | ** ** | **(94**                                    | **)**       | (270 | ) |
| Other,  net                                                                             | ** ** | **35**                                     |        | (462 | ) |
|                                                                                    | ** ** | **2,714**                                  |        | 2,506 |   |
| **Interest charges:**                                                                   |       |                                       |        |   |   |
| Long-term  debt                                                                         | ** ** | **20,547**                                 |        | 16,911 |   |
| Note  payable to securitization trust                                                   | ** ** | **2,125**                                  |        | 2,125 |   |
| Short-term  debt                                                                        | ** ** | **786**                                    |        | 843 |   |
| Allowance  for borrowed funds used during construction                                  | ** ** | **(4,303**                                 | **)**       | (2,862 | ) |
| Other                                                                                   | ** ** | **(299**                                   | **)**       | 567 |   |
|                                                                                    | ** ** | **18,856**                                 |        | 17,584 |   |
| ** **                                                                              | ** ** | ** **                                 |        |   |   |
| **Net income**                                                                          | ** ** | **$**                                      | **18,540**  |   | $ | 11,807 |   |
| ** **                                                                              | ** ** | ** **                                 |        |   |   |
| Weighted  average number of common shares outstanding - basic                           | ** ** | **34,129**                                 |        | 33,717 |   |
|                                                                                    | ** ** | ** **                                 |        |   |   |
| Weighted  average number of common shares outstanding - diluted                         | ** ** | **34,155**                                 |        | 33,747 |   |
| ** **                                                                              | ** ** | ** **                                 |        |   |   |
| **Total earnings per weighted average share of  common stock – basic and diluted** | ** ** | **$**                                      | **0.54**    |   | $ | 0.35 |   |
| ** **                                                                              | ** ** | ** **                                 |        |   |   |
| **Dividends per share of common stock**                                                 | ** ** | **$**                                      | **0.64**    |   | $ | 0.64 |   |

 

*See accompanying Notes to Consolidated Financial Statements.*

 

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**THEEMPIRE DISTRICT ELECTRIC COMPANY**

**CONSOLIDATEDSTATEMENTS OF OPERATIONS (UNAUDITED)**

 
| ** **                                                                                        | ** ** | **Twelve Months Ended**                    | ** **  |
|---------------------------------------------------------------------------------------------------|------------|--------------------------------------------|-------------|
| ** **                                                                                        | ** ** | **June 30,**                          | ** **  |
| ** **                                                                                        | ** ** | **2009**                                   | ** **  | **2008** | ** ** |
| ** **                                                                                        | ** ** | **(000’s except per share  amounts)** | ** **  |
| **Operating revenues:**                                                                           | ** ** | ** **                                 |        |   |   |
| Electric                                                                                          | ** ** | **$**                                      | **446,671** |   | $ | 439,525 |   |
| Gas                                                                                               | ** ** | **65,020**                                 |        | 60,273 |   |
| Water                                                                                             | ** ** | **1,764**                                  |        | 1,851 |   |
| Other                                                                                             | ** ** | **4,727**                                  |        | 3,837 |   |
|                                                                                              | ** ** | **518,182**                                |        | 505,486 |   |
| **Operating revenue deductions:**                                                                 | ** ** | ** **                                 |        |   |   |
| Fuel  and purchased power                                                                         | ** ** | **188,511**                                |        | 207,782 |   |
| Cost  of natural gas sold and transported                                                         | ** ** | **43,151**                                 |        | 37,180 |   |
| Regulated  operating expenses                                                                     | ** ** | **71,934**                                 |        | 71,354 |   |
| Other  operating expenses                                                                         | ** ** | **1,895**                                  |        | 1,601 |   |
| Maintenance  and repairs                                                                          | ** ** | **32,748**                                 |        | 27,439 |   |
| Gain  on sale of assets                                                                           | ** ** | **—**                                 |        | (1,241 | ) |
| Depreciation  and amortization                                                                    | ** ** | **51,491**                                 |        | 54,302 |   |
| Provision  for income taxes                                                                       | ** ** | **23,600**                                 |        | 15,074 |   |
| Other  taxes                                                                                      | ** ** | **26,043**                                 |        | 25,580 |   |
|                                                                                              | ** ** | **439,373**                                |        | 439,071 |   |
|                                                                                              | ** ** | ** **                                 |        |   |   |
| **Operating income**                                                                              | ** ** | **78,809**                                 |        | 66,415 |   |
| **Other income and (deductions):**                                                                | ** ** | ** **                                 |        |   |   |
| Allowance  for equity funds used during construction                                              | ** ** | **5,950**                                  |        | 3,979 |   |
| Interest  income                                                                                  | ** ** | **572**                                    |        | 768 |   |
| Benefit  (provision) for other income taxes                                                       | ** ** | **178**                                    |        | (319 | ) |
| Other,  net                                                                                       | ** ** | **(1,073**                                 | **)**       | (946 | ) |
|                                                                                              | ** ** | **5,627**                                  |        | 3,482 |   |
| **Interest charges:**                                                                             | ** ** | ** **                                 |        |   |   |
| Long-term  debt                                                                                   | ** ** | **39,677**                                 |        | 33,027 |   |
| Note  payable to securitization trust                                                             | ** ** | **4,250**                                  |        | 4,250 |   |
| Short-term  debt                                                                                  | ** ** | **1,796**                                  |        | 2,441 |   |
| Allowance  for borrowed funds used during construction                                            | ** ** | **(8,029**                                 | **)**       | (5,484 | ) |
| Other                                                                                             | ** ** | **287**                                    |        | 1,058 |   |
|                                                                                              | ** ** | **37,981**                                 |        | 35,292 |   |
| **Income from continuing operations**                                                             | ** ** | **46,455**                                 |        | 34,605 |   |
| Income  from discontinued operations, net of tax                                                  | ** ** | **—**                                 |        | 111 |   |
| ** **                                                                                        | ** ** | ** **                                 |        |   |   |
| **Net income**                                                                                    | ** ** | **$**                                      | **46,455**  |   | $ | 34,716 |   |
| ** **                                                                                        | ** ** | ** **                                 |        |   |   |
| Weighted  average number of common shares outstanding – basic                                | ** ** | **34,025**                                 |        | 32,265 |   |
| Weighted  average number of common shares outstanding – diluted                              | ** ** | **34,067**                                 |        | 32,294 |   |
|                                                                                              | ** ** | ** **                                 |        |   |   |
| Earnings  from continuing operations per weighted average share of common stock– basic       | ** ** | **$**                                      | **1.37**    |   | $ | 1.07 |   |
| Earnings  from discontinued operations per weighted average share of common stock –  basic   | ** ** | **$**                                      | **—**  |   | $ | 0.01 |   |
| **Total earnings per weighted average share of  common stock**–**basic**                     | ** ** | **$**                                      | **1.37**    |   | $ | 1.08 |   |
| Earnings  from continuing operations per weighted average share of common stock–  diluted    | ** ** | **$**                                      | **1.36**    |   | $ | 1.07 |   |
| Earnings  from discontinued operations per weighted average share of common stock –  diluted | ** ** | **$**                                      | **—**  |   | $ | 0.01 |   |
| **Total earnings per weighted average share of  common stock**–**diluted**                   | ** ** | **$**                                      | **1.36**    |   | $ | 1.08 |   |
| **Dividends per share of common stock**                                                           | ** ** | **$**                                      | **1.28**    |   | $ | 1.28 |   |

 

*See accompanying Notes to Consolidated Financial Statements.*

 

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**THE EMPIRE DISTRICT ELECTRIC COMPANY**

**CONSOLIDATED STATEMENTS OFCOMPREHENSIVE INCOME (UNAUDITED)**

 
| ** **                                                                                                             | ** ** | **Three Months Ended**  | ** ** |
|------------------------------------------------------------------------------------------------------------------------|------------|-------------------------|------------|
| ** **                                                                                                             | ** ** | **June 30,**       | ** ** |
| ** **                                                                                                             | ** ** | **2009**                | ** ** | **2008** | ** ** |
| ** **                                                                                                             | ** ** | **($-000’s)**      | ** ** |
|                                                                                                                   | ** ** | ** **              |       |   |   |
| **Net income**                                                                                                         | ** ** | **$**                   | **7,627**  |   | $ | 4,817 |   |
| Reclassification  adjustments for (gain)/loss included in net income or reclassified to  regulatory asset or liability | ** ** | **1,739**               |       | (1,713 | ) |
| Net  change in fair market value of derivative contracts for period                                                    | ** ** | **1,866**               |       | 22,806 |   |
| Income  taxes                                                                                                          | ** ** | **(1,374**              | **)**      | (8,036 | ) |
| ** **                                                                                                             | ** ** | ** **              |       |   |   |
| **Comprehensive income**                                                                                               | ** ** | **$**                   | **9,858**  |   | $ | 17,874 |   |
|                                                                                                                   |       |                    | ** ** | ** ** | ** ** |
| ** **                                                                                                             | ** ** | **Six Months Ended**    | ** ** |
| ** **                                                                                                             | ** ** | **June 30,**       | ** ** |
| ** **                                                                                                             | ** ** | **2009**                | ** ** | **2008** | ** ** |
| ** **                                                                                                             | ** ** | **($-000’s)**      | ** ** |
|                                                                                                                   |       |                    |       |   |   |
| **Net income**                                                                                                         | ** ** | **$**                   | **18,540** |   | $ | 11,807 |   |
| Reclassification  adjustments for (gain)/loss included in net income or reclassified to  regulatory asset or liability |       | **6,665**               |       | (2,573 | ) |
| Net  change in fair market value of derivative contracts for period                                                    | ** ** | **(7,467**              | **)**      | 33,829 |   |
| Income  taxes                                                                                                          | ** ** | **306**                 |       | (11,909 | ) |
|                                                                                                                   |       |                    |       |   |   |
| **Comprehensive income**                                                                                               | ** ** | **$**                   | **18,044** |   | $ | 31,154 |   |
|                                                                                                                   |       |                    |       |   |   |
| ** **                                                                                                             | ** ** | **Twelve Months Ended** | ** ** |
| ** **                                                                                                             | ** ** | **June 30,**       | ** ** |
| ** **                                                                                                             | ** ** | **2009**                | ** ** | **2008** | ** ** |
| ** **                                                                                                             | ** ** | **($-000’s)**      | ** ** |
|                                                                                                                   | ** ** | ** **              |       |   |   |
| **Net income**                                                                                                         | ** ** | **$**                   | **46,455** |   | $ | 34,716 |   |
| Reclassification  adjustments for (gain)/loss included in net income or reclassified to  regulatory asset or liability | ** ** | **5,365**               |       | (4,130 | ) |
| Net  change in fair market value of derivative contracts for period                                                    | ** ** | **(58,689**             | **)**      | 30,445 |   |
| Income  taxes                                                                                                          | ** ** | **20,316**              |       | (10,026 | ) |
| ** **                                                                                                             | ** ** | ** **              |       |   |   |
| **Comprehensive income**                                                                                               | ** ** | **$**                   | **13,447** |   | $ | 51,005 |   |

 

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

 

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**THE EMPIRE DISTRICT ELECTRIC COMPANY**

**CONSOLIDATEDBALANCE SHEETS (UNAUDITED)**

 
| ** **                                            | ** ** | **June 30, 2009** | ** **    | **December 31, 2008** | ** ** |
|-------------------------------------------------------|------------|------------------------|---------------|----------------------------|------------|
| ** **                                            | ** ** | **($-000’s)**     | ** **    |
| **Assets**                                            |       |                   |          |                       |       |
| Plant and property, at original cost:                 |       |                   |          |                       |       |
| Electric                                              | ** ** | **$**                  | **1,591,255** |                       | $          | 1,485,235 |   |
| Natural gas                                           | ** ** | **57,178**             |          | 56,282                     |       |
| Water                                                 | ** ** | **10,818**             |          | 10,560                     |       |
| Other                                                 | ** ** | **29,280**             |          | 28,481                     |       |
| Construction work in progress                         | ** ** | **262,600**            |          | 289,460                    |       |
|                                                  | ** ** | **1,951,131**          |          | 1,870,018                  |       |
| Accumulated depreciation and amortization             | ** ** | **545,334**            |          | 527,245                    |       |
|                                                  | ** ** | **1,405,797**          |          | 1,342,773                  |       |
|                                                  | ** ** | ** **             |          |                       |       |
| **Current assets:**                                   | ** ** | ** **             |          |                       |       |
| Cash and cash equivalents                             | ** ** | **3,391**              |          | 2,754                      |       |
| Accounts receivable – trade, net                 | ** ** | **35,169**             |          | 39,487                     |       |
| Accrued unbilled revenues                             | ** ** | **21,192**             |          | 25,170                     |       |
| Accounts receivable – other                      | ** ** | **14,453**             |          | 19,353                     |       |
| Fuel, materials and supplies                          | ** ** | **46,125**             |          | 54,202                     |       |
| Unrealized gain in fair value of derivative contracts | ** ** | **1,924**              |          | 2,395                      |       |
| Prepaid expenses and other                            | ** ** | **6,242**              |          | 5,675                      |       |
| Regulatory assets                                     | ** ** | **2,263**              |          | 2,033                      |       |
|                                                  | ** ** | **130,759**            |          | 151,069                    |       |
|                                                  | ** ** | ** **             |          |                       |       |
| **Noncurrent assets and deferred  charges:**          | ** ** | ** **             |          |                       |       |
| Regulatory assets                                     | ** ** | **156,941**            |          | 162,026                    |       |
| Goodwill                                              | ** ** | **39,492**             |          | 39,492                     |       |
| Unamortized debt issuance costs                       | ** ** | **11,093**             |          | 9,133                      |       |
| Unrealized gain in fair value of derivative contracts | ** ** | **5,282**              |          | 6,434                      |       |
| Other                                                 | ** ** | **3,215**              |          | 2,919                      |       |
|                                                  | ** ** | **216,023**            |          | 220,004                    |       |
| **Total Assets**                                      | ** ** | **$**                  | **1,752,579** |                       | $          | 1,713,846 |   |

 

(Continued)

 

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

 

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**THE EMPIRE DISTRICT ELECTRIC COMPANY**

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

** **
| ** **                                                                                         | ** ** | **June 30, 2009** | ** **    | **December 31, 2008** | ** ** |
|----------------------------------------------------------------------------------------------------|------------|------------------------|---------------|----------------------------|------------|
| ** **                                                                                         | ** ** | **($-000’s)**     | ** **    |
| **Capitalization and Liabilities**                                                                 |       |                   |          |                       |       |
| Common stock, $1 par value, 34,267,124 and 33,981,579 shares  issued and outstanding, respectively |       | **$**                  | **34,267**    |                       | $          | 33,982 |   |
| Capital in excess of par value                                                                     | ** ** | **486,955**            |          | 483,443                    |       |
| Retained earnings                                                                                  | ** ** | **10,260**             |          | 13,579                     |       |
| Accumulated other comprehensive loss, net of income  tax                                           | ** ** | **(2,628**             | **)**         | (2,132                     | )          |
| **Total common stockholders’  equity**                                                        | ** ** | **528,854**            |          | 528,872                    |       |
|                                                                                               | ** ** | ** **             |          |                       |       |
| **Long-term debt (net of current  portion):**                                                      | ** ** | ** **             |          |                       |       |
| Note payable to securitization trust                                                               | ** ** | **50,000**             |          | 50,000                     |       |
| Obligations under capital lease                                                                    | ** ** | **223**                |          | 174                        |       |
| First mortgage bonds and secured debt                                                              | ** ** | **339,045**            |          | 312,953                    |       |
| Unsecured debt                                                                                     | ** ** | **248,243**            |          | 248,440                    |       |
| **Total long-term debt**                                                                           | ** ** | **637,511**            |          | 611,567                    |       |
| **Total long-term debt and common  stockholders’ equity**                                     | ** ** | **1,166,365**          |          | 1,140,439                  |       |
|                                                                                               | ** ** | ** **             |          |                       |       |
| **Current liabilities:**                                                                           | ** ** | ** **             |          |                       |       |
| Accounts payable and accrued liabilities                                                           | ** ** | **45,131**             |          | 69,502                     |       |
| Current maturities of long-term debt                                                               | ** ** | **70,539**             |          | 20,160                     |       |
| Short-term debt                                                                                    | ** ** | **72,000**             |          | 102,000                    |       |
| Customer deposits                                                                                  | ** ** | **9,776**              |          | 9,577                      |       |
| Interest accrued                                                                                   | ** ** | **6,255**              |          | 5,921                      |       |
| Unrealized loss in fair value of derivative contracts                                              | ** ** | **7,429**              |          | 12,276                     |       |
| Taxes accrued                                                                                      | ** ** | **10,581**             |          | 3,174                      |       |
|                                                                                               | ** ** | **221,711**            |          | 222,610                    |       |
| **Commitments and contingencies  (Note 7)**                                                        | ** ** | ** **             |          |                       |       |
| **Noncurrent liabilities and  deferred credits:**                                                  | ** ** | ** **             |          |                       |       |
| Regulatory liabilities                                                                             | ** ** | **71,643**             |          | 66,585                     |       |
| Deferred income taxes                                                                              | ** ** | **179,741**            |          | 173,511                    |       |
| Unamortized investment tax credits                                                                 | ** ** | **2,744**              |          | 2,917                      |       |
| Pension and other postretirement benefit obligations                                               | ** ** | **85,913**             |          | 83,151                     |       |
| Unrealized loss in fair value of derivative contracts                                              | ** ** | **3,846**              |          | 3,302                      |       |
| Other                                                                                              | ** ** | **20,616**             |          | 21,331                     |       |
| ** **                                                                                         | ** ** | **364,503**            |          | 350,797                    |       |
| **Total Capitalization and  Liabilities**                                                          | ** ** | **$**                  | **1,752,579** |                       | $          | 1,713,846 |   |

 

*Seeaccompanying Notes to Consolidated Financial Statements.*

 

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**THEEMPIRE DISTRICT ELECTRIC COMPANY**

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

 
| ** **                                                                        | ** ** | **Six Months Ended** | ** ** |
|-----------------------------------------------------------------------------------|------------|----------------------|------------|
| ** **                                                                        | ** ** | **June 30,**    | ** ** |
| ** **                                                                        | ** ** | **2009**             | ** ** | **2008** | ** ** |
| ** **                                                                        | ** ** | **($-000’s)**   | ** ** |
| **Operating activities:**                                                         | ** ** | ** **           |       |   |   |
| Net  income                                                                       |       | $                    | 18,540     |   | $ | 11,807 |   |
| **Adjustments to reconcile net income to cash  flows from operating activities**: |       |                 |       |   |   |
| Depreciation  and amortization                                                    |       | 29,903               |       | 29,471 |   |
| Pension  and other postretirement benefit costs                                   |       | 2,803                |       | 4,720 |   |
| Deferred  income taxes and unamortized investment tax credit, net                 |       | 5,321                |       | 556 |   |
| Allowance  for equity funds used during construction                              |       | (2,636               | )          | (2,615 | ) |
| Stock  compensation expense                                                       |       | 1,398                |       | 1,543 |   |
| Non-cash  (gain)/loss on derivatives                                              |       | 6,034                |       | (1,705 | ) |
| Gain  on sale of assets                                                           |       | (504                 | )          | — |   |
| Iatan  deferred construction accounting costs                                     |       | (615                 | )          | — |   |
| **Cash flows impacted by changes in:**                                            |       |                 |       |   |   |
| Accounts  receivable and accrued unbilled revenues                                |       | 6,714                |       | 11,751 |   |
| Fuel,  materials and supplies                                                     |       | 8,077                |       | 442 |   |
| Prepaid  expenses, other current assets and deferred charges                      |       | (2,496               | )          | (1,588 | ) |
| Accounts  payable and accrued liabilities                                         |       | (21,462              | )          | 4,134 |   |
| Customer  deposits, interest and taxes accrued                                    |       | 7,940                |       | 8,101 |   |
| Other  liabilities and other deferred credits                                     |       | 968                  |       | (496 | ) |
|                                                                              |       |                 |       |   |   |
| **Net cash provided by operating activities**                                     |       | 59,985               |       | 66,121 |   |
| ** **                                                                        | ** ** | ** **           |       |   |   |
| **Investing activities:**                                                         | ** ** | ** **           |       |   |   |
| Capital  expenditures – regulated                                            |       | (83,613              | )          | (114,130 | ) |
| Capital  expenditures and other investments – other                          |       | (876                 | )          | (919 | ) |
| Proceeds  from the sale of property, plant and equipment                          |       | 544                  |       | 807 |   |
|                                                                              |       |                 |       |   |   |
| **Net cash used in investing activities**                                         |       | (83,945              | )          | (114,242 | ) |
| ** **                                                                        | ** ** | ** **           |       |   |   |
| **Financing activities:**                                                         | ** ** | ** **           |       |   |   |
| Proceeds  from first mortgage bonds - electric                                    |       | 75,000               |       | 89,950 |   |
| Proceeds  from notes payable                                                      |       | 1,431                |       | — |   |
| Long-term  debt issuance costs                                                    |       | (2,396               | )          | (3,096 | ) |
| Proceeds  from issuance of common stock net of issuance costs                     |       | 2,589                |       | 3,366 |   |
| Net  short-term debt repayments                                                   |       | (30,000              | )          | (21,040 | ) |
| Dividends                                                                         |       | (21,859              | )          | (21,586 | ) |
| Other                                                                             |       | (168                 | )          | (167 | ) |
| ** **                                                                        |       |                 |       |   |   |
| **Net cash provided by financing activities**                                     |       | 24,597               |       | 47,427 |   |
| ** **                                                                        |       |                 |       |   |   |
| **Net increase (decrease) in cash and cash  equivalents**                         |       | 637                  |       | (694 | ) |
| ** **                                                                        |       |                 |       |   |   |
| **Cash and cash equivalents at beginning of period**                              |       | 2,754                |       | 4,043 |   |
| ** **                                                                        |       |                 |       |   |   |
| **Cash and cash equivalents at end of period**                                    |       | $                    | 3,391      |   | $ | 3,349 |   |

 

*See accompanying Notes to Consolidated Financial Statements.*

 

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**NOTES TOCONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)**

 

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

 

We operate our businesses asthree segments:  electric, gas and other.The Empire District Electric Company (EDE), a Kansas corporation organized in1909, is an operating public utility engaged in the generation, purchase,transmission, distribution and sale of electricity in parts of Missouri,Kansas, Oklahoma and Arkansas. As part of our electric segment, we also providewater service to three towns in Missouri. The Empire District Gas Company (EDG)is our wholly-owned subsidiary which provides natural gas distribution tocommunities in northwest, north central and west central Missouri. Our othersegment is held by our wholly-owned subsidiary, EDE Holdings, Inc. (EDEHoldings) and primarily consists of a 100% interest in Empire DistrictIndustries Inc., a subsidiary for our fiber optics business.

 

Theaccompanying interim financial statements do not include all disclosuresincluded in the annual financial statements and therefore should be read inconjunction with the financial statements and notes thereto included in ourAnnual Report on Form 10-K for the fiscal year ended December 31,2008. Subsequent events were evaluated through August 6, 2009, the datethese financial statements were issued.

 

The information furnished reflects all adjustments, consisting only ofnormal recurring adjustments, which are in our opinion necessary to statefairly the results for the interim periods as well as present these periods ona consistent basis with the financial statements for the fiscal year ended December 31,2008.

 

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

 

Weadopted Statement of Financial Accounting Standards (SFAS) No. 157, “FairValue Measurements,” (FAS 157) on January 1, 2008. This statement definesfair value, establishes a framework for measuring fair value in generallyaccepted accounting principles and expands disclosures about fair valuemeasurements. This statement applies under other accounting pronouncements thatrequire or permit fair value measurements. FASB Staff Position (FSP) 157-1,issued in February 2008, amended FAS 157 to exclude FASB Statement No. 13,“Accounting for Leases” (FAS 13) and other accounting pronouncements thataddress fair value measurements for purposes of lease classification ormeasurement under FAS 13. The adoption of FAS 157 for financial assets andfinancial liabilities did not have a material impact on our consolidatedfinancial position, results of operations and cash flows. FASB Staff Position(FSP) 157-2 amended FAS 157 to delay the effective date of FAS 157 for allnonfinancial assets and nonfinancial liabilities to fiscal years beginningafter November 15, 2008. We adopted this portion of the standard on January 1,2009. The adoption of FAS 157 for nonfinancial assets and nonfinancialliabilities did not have an effect on our consolidated financial position,results of operations or cash flows. (See Note 5).

 

In April 2008, the FASBissued SFAS No. 161 “Disclosure About Derivative Instruments and HedgingActivities, an Amendment of FASB Statement No. 133” (FAS 161). FAS 161enhances the current disclosure framework in SFAS No. 133, “Accounting forDerivative Instruments and Hedging Activities.” FAS 161 is effective forperiods beginning after November 15, 2008. We adopted this statement on January 1,2009. The adoption of FAS 161 did not have a material effect on our financialstatement disclosures (See Note 4 below).

 

InMay 2009, the FASB issued SFAS No. 165 “Subsequent Events” (FAS 165).This statement is effective for periods ending after June 15, 2009. FAS165 requires the disclosure of the date through which an entity has evaluatedsubsequent events, and whether that date represents the date the financialstatements were issued or were available to be issued. We adopted thisstatement upon its issuance by the FASB. The adoption of FAS 165 did not have amaterial effect on our financial statement disclosures. (See Note 1 above).

 

InDecember 2008, the FASB issued FSP SFAS No. 132(R)-1, “Employers’ Disclosures about PostretirementBenefit Plan Assets”**(FAS 132(R)-1) which requires additional disclosures

 

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relatedto pension and other postretirement benefit plan assets. FAS 132 (R)-1 will be effective as ofDecember 31, 2009 and requires a separate disclosure of the fair value ofeach major category of plan assets of a defined benefit pension orpostretirement plan. In addition, employers are required to discloseinformation enabling users to understand investment policies and strategies,assess the inputs and valuation techniques used to develop fair valuemeasurements, and to disclose any significant concentrations of risks withinplan assets. We do not expect the adoption of FAS 132(R)-1 to have a material effecton our results of operations, financial position or liquidity because itprovides enhanced disclosure requirements only.

 

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

 

                In April 2009 the FASBissued FSP FAS 115-2 and FAS 124-2 “Recognition and Presentation ofOther-Than-Temporary Impairments” which changes the other-than-temporaryimpairment guidance in existing Generally Accepted Accounting Principles fordebt securities. FSP FAS 115-2 and FAS 124-2 provide for improved presentationand disclosure of other-than-temporary impairments of debt securities in thefinancial statements. This staff position was effective as of June 30,2009. The adoption of FSP FAS 115-2 and FAS 124-2 did not have a materialeffect on our result of operations, financial position or liquidity.

 

                In April 2009, the FASB issued FSP FAS No. 107-1and APB 28-1, “Interim Disclosures about Fair Value of Financial Instruments,”which amends FAS No. 107, “Disclosures about Fair Value of FinancialInstruments,” and APB Opinion No. 28, “Interim Financial Reporting,”respectively. FSP FAS No. 107-1 and APB 28-1 require disclosures aboutfair value of financial instruments in interim financial statements, inaddition to the annual financial statements as already required by FAS No.107.FSP FAS 107-1 and APB 28-1 is required for interim periods ending after June 15,2009. As FSP FAS 107-1 and APB 28-1 provide only disclosure requirements, theapplication of this standard did not have a material impact on our results ofoperations, financial position or liquidity. (See Note 5).

 

                In June 2009, the FASBissued SFAS No. 166 “Accounting for Transfers of Financial Assets — anamendment of FASB Statement No. 140” (FAS 166). This statement iseffective for annual periods beginning after November 15, 2009. FAS 166removes qualifying special-purpose entities (QSPE) from generally acceptedaccounting principles. Additionally, the requirements for derecognizingfinancial assets have been changed, and additional disclosures about atransferor’s continuing involvement in transferred financial assets will berequired. We do not expect the adoption of FAS 166 to have a material effect onour financial statements.

 

                In June 2009, the FASBissued SFAS No. 167 “Amendments to FASB interpretation No. 46(R)”(FAS 167). This statement is effective for annual periods beginning after November 15,2009. FAS 167 amends FASB Interpretation No. 46(R) (FIN 46(R)) torequire an entity to complete a qualitative analysis when determining who mustconsolidate a variable interest entity. Additionally, FAS 167 requiresadditional disclosures, and an ongoing reassessment of who must consolidate avariable interest entity. We are evaluating the impact of the adoption of thisstandard; however, we do not expect the adoption of this standard to have amaterial impact on our financial statements.

 

                In June 2009, the FASBissued SFAS No. 168 “The FASB Accounting Standards Codification and theHierarchy of Generally Accepted Accounting Principles — a replacement of FASBStatement No. 162” (FAS 168). This statement is effective for periodsending after September 15, 2009. FAS 168 identifies the sources ofaccounting principles, and establishes the FASB Accounting StandardsCodification (Codification) as the only source of authoritative accountingprinciples recognized by the FASB. This statement is not intended to changegenerally accepted accounting principles. Accordingly we do not expect theadoption of FAS 168 to have a material effect on our financial statements.

 

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See Note 1 under “Notes toConsolidated Financial Statements” in our Annual Report on Form 10-K forthe year ended December 31, 2008 for further information regardingrecently issued accounting standards.

 

**Note 3— Regulatory Matters**

 

                On April 19, 2009, we beganrecording deferred carrying charges associated with environmental upgradesrecently completed at our Iatan 1 facility in accordance with our regulatoryplan. The effect of these deferred carrying charges is reflected indepreciation and in other interest on the statement of operations. Constructionaccounting, for purposes of the regulatory plan, is specific to Iatan 1 andIatan 2 construction and allows us to defer certain charges as regulatoryassets, including depreciation and carrying costs, related to operation of thefacilities until the facilities are ultimately included in our rate base. Theamounts deferred, which began at the in-service date for Iatan 1 and will alsobe deferred for Iatan 2 at its in-service date, will then be amortized over thelife of the plants once they are in our rate base. The regulatory plan coversthe 150 megawatt V84.3A2 combustion turbine (Unit 12) that began commercialoperation on April 10, 2007 at our Riverton plant, the environmentalupgrades at Asbury, which were completed in 2008, environmental upgrades atIatan 1 and the construction of the Iatan 2 facilities.

 

                The following table sets forththe components of our regulatory assets and liabilities on our consolidatedbalance sheet (in thousands).

 

**Regulatory Assets and Liabilities**

 
| ** **                                                                 | ** ** | **June 30, 2009** | ** **    | **December 31, 2008** | ** ** |
|----------------------------------------------------------------------------|------------|------------------------|---------------|----------------------------|------------|
| **Regulatory Assets:**                                                     |       |                   |          |                       |       |
| Unrecovered  purchased gas costs — gas segment, current               |       | $                      |  336     |                       | $          |  1,791 |   |
| Unrecovered  electric fuel and purchased power costs — current**(1)** |       | 1,927                  |          | 242                        |       |
| Regulatory  assets, current                                                |       | $                      |  2,263   |                       | $          |  2,033 |   |
| Income  taxes                                                              |       | 35,671                 |          | 34,515                     |       |
| Unamortized  loss on reacquired debt                                       |       | 12,829                 |          | 13,490                     |       |
| Unamortized  loss on interest rate derivative                              |       | 2,248                  |          | 2,405                      |       |
| Asbury  five-year maintenance                                              |       | 1,628                  |          | 1,855                      |       |
| Pension  and other postretirement benefits**(2)**                          |       | 83,646                 |          | 84,926                     |       |
| Storm  costs**(3)**                                                        |       | 13,538                 |          | 14,704                     |       |
| Deferred  Iatan construction accounting costs**(4)**                       |       | 812                    |          | —                     |       |
| Asset  retirement obligation                                               |       | 3,198                  |          | 3,118                      |       |
| Unrecovered  purchased gas costs — gas segment                        |       | —                 |          | 3,787                      |       |
| Unsettled  derivative losses — electric segment                       |       | 1,080                  |          | 1,218                      |       |
| Other                                                                      |       | 2,291                  |          | 2,008                      |       |
| Regulatory  assets, long-term                                              |       | $                      |  156,941 |                       | $          |  162,026 |   |
| **Total**                                                                  |       | $                      |  159,204 |                       | $          |  164,059 |   |

 
| ** **                                                     | ** ** | **June 30, 2009** | ** **   | **December 31, 2008** | ** ** |
|----------------------------------------------------------------|------------|------------------------|--------------|----------------------------|------------|
| **Regulatory Liabilities:**                                    |       |                   |         |                       |       |
| Income  taxes                                                  |       | $                      |  11,123 |                       | $          |  11,126 |   |
| Unamortized  gain on interest rate derivative                  |       | 4,136                  |         | 4,221                      |       |
| Costs  of removal                                              |       | 48,102                 |         | 43,713                     |       |
| Pension  and other postretirement benefits**(5)**              |       | 6,135                  |         | 7,042                      |       |
| Over  recovered electric fuel and purchased power costs**(6)** |       | 1,569                  |         | 228                        |       |
| Other                                                          |       | 578                    |         | 255                        |       |
| **Total**                                                      |       | $                      |  71,643 |                       | $          |  66,585 |   |

 

----

(1) Reflectsunder recovered costs for the accumulation period from September 2008through February 2009 currently being recovered in Missouri rates.

(2) Primarilyreflects regulatory assets resulting from the unfunded portion of our pensionand OPEB liabilities and regulatory accounting for EDG acquisition costs.Approximately $0.3 million in pension and other postretirement benefit costshave been recognized since January 1, 2009 to reflect the amortization ofthe regulatory assets that were recorded at the time of the acquisition of theAquila, Inc. gas properties.

 

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(3) Primarilyreflects the amortization of ice storm costs but also includes deferred windstorm costs of $0.7 million incurred in May 2009. Consistent with recentrate case treatment, we expect to recover wind storm costs over a five yearperiod commencing when rates go into effect.

(4) Includes$0.2 million of deferred depreciation costs and $0.6 million in carrying costsrelated to construction accounting for Iatan 1, which will be amortized overthe life of the plant once it is included in rate base (see Note 1).

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

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

 

                There have been no changesto the rate base inclusions, expected recoverability or amortizable lives ofour regulatory assets and liabilities since December 31, 2008, other thanthe Iatan construction accounting carrying costs and wind storm costs discussedabove.

 

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

 

                We currently engage in hedgingactivities in an effort to minimize our risk from volatile natural gas prices.We enter into 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 expense and gain predictability. We recognize that ifrisk is not timely and adequately balanced or if counterparties fail to performcontractual obligations, actual results could differ materially from intendedresults.

 

                All derivative instruments arerecognized at fair value on the balance sheet with gains and losses deferred inother comprehensive income (in stockholders’ equity) for effective instrumentsrelated to our electric segment, entered into prior to September 1, 2008.All other instruments are deferred as a regulatory asset or liability, due to ourfuel recovery mechanism, effective September 1, 2008 for our electricsegment, and for our gas segment.

 

                For instruments entered intoprior to 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 Operationssince all of our gas hedging activities are related to stabilizing fuel costsas part of our fuel procurement program and are not speculative activities.Risks and uncertainties 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 Operations.

 

                As of June 30, 2009 and December 31,2008, we have recorded the following assets and liabilities representing thefair value of derivative financial instruments, (in thousands):

** **
| ** **                                                         | ** ** | ** **                               | ** ** | **June 30,** | ** ** | **December 31,** | ** ** |
|--------------------------------------------------------------------|------------|------------------------------------------|------------|-------------------|------------|-----------------------|------------|
| **ASSET DERIVATIVES**                                              | ** ** | **2009**                                 | ** ** | **2008**          | ** ** |
| **Derivatives  designated as hedging   instruments under FAS 133** | ** ** | **Balance Sheet Classification**         | ** ** | **Fair Value**    | ** ** | **Fair Value**        | ** ** |
| Natural gas contracts, electric segment                            |       | Current  assets                          |       | $                 |  763  |                  | $          |  1,214 |   |
|                                                               |       | Non-current  assets and deferred charges |       | 5,282             |       | 6,208                 |       |
|                                                                    |            |                                          |            |                   |            |                       |            |  |  |

 
| **Derivatives not designated as  hedging  instruments under FAS 133  due to regulatory accounting** |       |                                     |       |   |            |       |   |
|-----------------------------------------------------------------------------------------------------|------------|------------------------------------------|------------|--------|-----------------|------------|--------|
| Natural gas contracts, gas segment                                                                  |       | Current  assets                          |       | 1,161  |            | 1,177      |   |
|                                                                                                |       | Non-current  assets and deferred charges |       | — |            | 226        |   |
|                                                                                                |       |                                     |       |   |            |       |   |
| Natural gas contracts, electric segment                                                             |       | Current  assets                          |       | — |            | 4          |   |
| **Total derivatives assets**                                                                        | ** ** | ** **                               | ** ** | **$**  | ** 7,206** | ** ** | **$**  | ** 8,829** | ** ** |
|                                                                                                     |            |                                          |            |        |                 |            |        |  |  |

 

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| ** **                                                         | ** ** | ** **                                    | ** ** | **June 30,** | ** **  | **December 31,** | ** ** |
|--------------------------------------------------------------------|------------|-----------------------------------------------|------------|-------------------|-------------|-----------------------|------------|
| **LIABILITY DERIVATIVES**                                          | ** ** | **2009**                                      | ** ** | **2008**          | ** **  |
| **Derivatives  designated as hedging   instruments under FAS 133** | ** ** | **Balance Sheet Classification**              | ** ** | **Fair Value**    | ** **  | **Fair Value**        | ** ** |
| Natural gas contracts, electric segment                            |       | Current  liabilities                          |       | $                 |  4,666 |                  | $          |  6,254 |   |
|                                                               |       | Non-current  liabilities and deferred credits |       | 3,846             |        | 3,282                 |       |
|                                                                    |            |                                               |            |                   |             |                       |            |  |  |

 
| **Derivatives not designated as  hedging   instruments under FAS 133****due to regulatory accounting** | ** ** | ** **                                    | ** ** | ** ** | ** **       | ** ** | ** ** |
|--------------------------------------------------------------------------------------------------------|------------|-----------------------------------------------|------------|------------|------------------|------------|------------|
| Natural gas contracts, gas segment                                                                     |       | Current  liabilities                          |       | $          |  1,374      |       | $          |  4,474 |   |
|                                                                                                   |       | Non-current  liabilities and deferred credits |       | —     |             | 20         |       |
| Natural gas contracts, electric segment                                                                |       | Current  liabilities                          |       | 1,389      |             | 1,548      |       |
| **Total derivatives liabilities**                                                                      | ** ** | ** **                                    | ** ** | **$**      | ** 11,275** | ** ** | **$**      | ** 15,578** | ** ** |

 

*Electric*

 

                A $(2.6) million net of tax,unrealized loss representing the fair market value of our electric segmentderivative contracts treated as cash flow hedges is recognized as AccumulatedOther Comprehensive Income in the capitalization section of the balance sheetas of June 30, 2009. The tax effect of $1.6 million on this loss isincluded in deferred taxes. These amounts will be adjusted cumulatively on amonthly basis during the determination periods, beginning July 1, 2009 andending on September 30, 2011. At the end of each determination period, orif cash flow hedge treatment is discontinued, any realized gain or loss forthat period related to the instrument will be reclassified to fuel expense. As ofJune 30, 2009, approximately $6.1 million of these unrealized losses areapplicable to financial instruments which will settle within the next twelvemonths.

 

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

 

                The following tables set forththe actual pre-tax gains/(losses) and the mark to market effect of unsettledpositions from the qualified portion of our hedging activities for the electricsegment for each of the periods ended June 30, (in thousands):

 
| **Derivatives in FAS 133   Cash Flow Hedging**       |       | **Statement  of   Operations   Classification of** |       | **Amount  of Gain / (Loss) Reclassed from OCI into Income  (Effective portion)** |             |
|------------------------------------------------------|------------|----------------------------------------------------|------------|----------------------------------------------------------------------------------|------------------|
| **Relationships - Electric**                         |       | **Gain /  (Loss) on**                              |       | **Three  Months Ended**                                                          | ** **       | **Six  Months Ended** | ** ** | **Twelve  Months Ended** |   |
| **Segment**                                          |       | **Derivative**                                     |       | **2009**                                                                         | ** **       | **2008** | ** ** | **2009** | ** ** | **2008** | ** ** | **2009** | ** ** | **2008** |   |
| Commodity contracts                                  |       | Fuel  and purchased power expense                  |       | $                                                                                |  (1,739     | ) | $ |  1,713 |   | $ |  (6,665 | ) | $ |  2,573 |   | $ |  (5,365 | ) | $ |  4,130 |   |
|                                                 |       |                                               |       |                                                                             |             |   |   |   |   |   |   |   |   |   |   |
| **Total Effective —**** Electric Segment** | ** ** | ** **                                         | ** ** | **$**                                                                            | ** (1,739** | **)** | **$** | ** 1,713** | ** ** | **$** | ** (6,665** | **)** | **$** | ** 2,573** | ** ** | **$** | ** (5,365** | **)** | **$** | ** 4,130** | ** ** |

 
| **Derivatives  in FAS  133 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**                                                    | ** ** | **2009**                                                                               | ** **      | **2008** | ** ** | **2009** | ** ** | **2008** | ** ** | **2009** | ** ** | **2008** | ** ** |
| Commodity  contracts                                 |       | Net change in fair  market value of open derivative contracts |       | $                                                                                      |   1,866    |   | $ |   22,806 |   | $ |   (7,467 | ) | $ |   33,829 |   | $ |  (58,689 | ) | $ |   30,445 |   |
|                                                 |       |                                                          |       |                                                                                   |            |   |   |   |   |   |   |   |   |   |   |
| **Total Effective —**** Electric Segment** | ** ** | ** **                                                    | ** ** | **$**                                                                                  | ** 1,866** | ** ** | **$** | ** 22,806** | ** ** | **$** | ** (7,467** | **)** | **$** | ** 33,829** | ** ** | **$** | ** (58,689** | **)** | **$** | ** 30,445** | ** ** |

 

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                The following table sets forth “mark-to-market”pre-tax gains/(losses) from the ineffective portion of our hedging activitiesfor the electric segment for each of the periods ended June 30, (inthousands):

 
| **Derivatives in FAS 133   Cash Flow Hedging**         |       | **Statement  of   Operations   Classification of** |       | **Amount of Gain / (Loss) Recognized in Income on Derivative********(Ineffective portion)** |             |
|--------------------------------------------------------|------------|----------------------------------------------------|------------|---------------------------------------------------------------------------------------------|------------------|
| **Relationships - Electric**                           |       | **Gain /  (Loss) on**                              |       | **Three  Months Ended**                                                                     | ** **       | **Six  Months Ended** | ** ** | **Twelve  Months Ended** |   |
| **Segment**                                            |       | **Derivative**                                     |       | **2009**                                                                                    | ** **       | **2008** | ** ** | **2009** | ** ** | **2008** | ** ** | **2009** | ** ** | **2008** |   |
| Commodity contracts                                    |       | Fuel  and purchased power expense                  |       | $                                                                                           |  —     |   | $ |  1 |   | $ |  — |   | $ |  (267 | ) | $ |  (2 | ) | $ |  14 |   |
|                                                   |       |                                               |       |                                                                                        |             |   |   |   |   |   |   |   |   |   |   |
| **Total Ineffective —**** Electric Segment** | ** ** | ** **                                         | ** ** | **$**                                                                                       | ** —** | ** ** | **$** | ** 1** | ** ** | **$** | ** —** | ** ** | **$** | ** (267** | **)** | **$** | ** (2** | **)** | **$** | ** 14** | ** ** |

 

                The following tables set forth “mark-to-market”pre-tax gains/(losses) from derivatives not designated as hedging instrumentsunder FAS 133 for the electric segment for each of the periods ended June 30,(in thousands):

 
| **Derivatives  Not**          |       | ** **                       |       | ** **                                              |          |
|-------------------------------|------------|----------------------------------|------------|---------------------------------------------------------|---------------|
| **Designated  as Hedging**    |       | ** **                       |       | ** **                                              |          |
| **Instruments  Under FAS**    |       | **Balance Sheet**                |       | ** **                                              |          |
| **133 -  Due to Regulatory**  |       | **Classification of**            |       | **Amount of Gain / (Loss) Recognized on Balance Sheet** |          |
| **Accounting**                |       | **Gain / (Loss)  on**            |       | **Three  Months Ended**                                 | ** **    | **Six  Months Ended** | ** ** | **Twelve  Months Ended** |   |
| **Electric  Segment(1)** |       | **Derivative**                   |       | **2009**                                                | ** **    | **2008** | ** ** | **2009** | ** ** | **2008** | ** ** | **2009** | ** ** | **2008** |   |
| Commodity contracts           |       | Regulatory  (assets)/liabilities |       | $                                                       |  (74     | ) | $ |  — |   | $ |  (543 | ) | $ |  — |   | $ |  (2,088 | ) | $ |  — |   |
|                          |       |                             |       |                                                    |          |   |   |   |   |   |   |   |   |   |   |
| **Total Electric Segment**    | ** ** | ** **                       | ** ** | **$**                                                   | ** (74** | **)** | **$** | ** —** | ** ** | **$** | ** (543** | **)** | **$** | ** —** | ** ** | **$** | ** (2,088** | **)** | **$** | ** —** | ** ** |

 
| **Derivatives  Not   Designated as Hedging   Instruments Under FAS  133 - Due to Regulatory** |       | **Statement  of   Operations   Classification of** |       | **Amount of Gain / (Loss) Recognized in Income on Derivative** |          |
|-----------------------------------------------------------------------------------------------|------------|----------------------------------------------------|------------|----------------------------------------------------------------|---------------|
| **Accounting**                                                                                |       | **Gain /  (Loss) on**                              |       | **Three  Months Ended**                                        | ** **    | **Six  Months Ended** | ** ** | **Twelve  Months Ended** |   |
| **Electric  Segment(1)**                                                                 |       | **Derivative**                                     |       | **2009**                                                       | ** **    | **2008** | ** ** | **2009** | ** ** | **2008** | ** ** | **2009** | ** ** | **2008** |   |
| Commodity contracts                                                                           |       | Fuel  and purchased power expense                  |       | $                                                              |  (30     | ) | $ |  — |   | $ |  (678 | ) | $ |  — |   | $ |  (1,007 | ) | $ |  — |   |
|                                                                                          |       |                                               |       |                                                           |          |   |   |   |   |   |   |   |   |   |   |
| **Total Electric Segment**                                                                    | ** ** | ** **                                         | ** ** | **$**                                                          | ** (30** | **)** | **$** | ** —** | ** ** | **$** | ** (678** | **)** | **$** | ** —** | ** ** | **$** | ** (1,007** | **)** | **$** | ** —** | ** ** |

 

----

**(1) **As all gas hedging activities are related to stabilizing fuel costs, ifconditions change, such as a planned unit outage, we may need to unwind some ofour previous derivatives accounted for under FAS 133.

 

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

 

                As of July 24, 2009, 92% ofour anticipated volume of natural gas usage for our electric operations for theremainder of 2009 is hedged, either through physical (1.7 million Dths) orfinancial contracts (2.6 million Dths), at an average price of $6.009 perDekatherm (Dth). In addition, the following volumes and percentages of ouranticipated volume of natural gas usage for our electric operations for thenext four years are hedged at the following average prices per Dth:

 

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| **Year** | ** ** | **% Hedged** | ** ** | **Dth Hedged** | ** ** | **Average Price** | ** ** |
|----------|------------|--------------|------------|----------------|------------|-------------------|------------|
| 2010(1)  |       | 81           | %          | 7,225,000      |       | $                 | 6.317      |   |
| 2011(1)  |       | 60           | %          | 5,115,000      |       | $                 | 5.840      |   |
| 2012     |       | 20           | %          | 1,665,000      |       | $                 | 7.123      |   |
| 2013     |       | 12           | %          | 1,200,000      |       | $                 | 7.295      |   |

 

----

(1) 3 million Dthand 2 million Dth of the anticipated volume of natural gas usage for 2010 and2011, respectively, are hedged through financial derivative contracts.

 

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

 

                On February 15,2008, we unwound 992,000 Dth of physical gas contracts originally scheduled fordelivery in July and August of 2010 and 2011. This transactionresulted in a gain of approximately $1.3 million after tax which was recordedas a reduction to fuel and purchased power expense in the Statement ofOperations for the six and twelve months ended June 30, 2008. We believeit is probable that we will take physical delivery under the remaining physicalgas forward contracts.

 

*Gas*

 

                Weattempt to mitigate our natural gas price risk for our gas segment by acombination of (1) injecting natural gas into storage during theoff-heating season months, (2) purchasing physical forward contracts and (3) purchasingfinancial derivative contracts. We target to have 95% of our storage capacityfull by November 1 for the upcoming winter heating season. As the winterprogresses, gas is withdrawn from storage to serve our customers. As of July 24,2009, we had 1.2 million Dths in storage on the three pipelines that serve ourcustomers. This represents 60% of our storage capacity. We have an additional1.0 million Dths hedged through financial derivative and physical contracts.Our long-term hedge strategy is to mitigate price volatility for our customersby hedging a minimum of 50% of current year, up to 50% of second year and up to20% of third year expected gas usage by the beginning of the Actual CostAdjustment (ACA) year at September 1.A Purchased Gas Adjustment (PGA) clause is included in our rates for our gassegment operations, therefore, we mark to market any unrealized gains or lossesand any realized gains or losses relating to financial derivative contracts toa regulatory asset or regulatory liability account on our balance sheet.

 

                The following table sets forth “mark-to-market”pre-tax gains / (losses) from derivatives not designated as hedging instrumentsunder FAS 133 for the gas segment for each of the periods ended June 30,(in thousands).

 
| **Derivatives  Not Designated as   Hedging Instruments Under** |       | **Balance Sheet  Classification of** |       | **Amount of Gain / (Loss) Recognized on Balance Sheet** |         |
|----------------------------------------------------------------|------------|--------------------------------------|------------|---------------------------------------------------------|--------------|
| **FAS 133 Due to Regulatory**                                  |       | **Gain /  (Loss) on**                |       | **Three  Months Ended**                                 | ** **   | **Six  Months Ended** | ** ** | **Twelve  Months Ended** |   |
| **Accounting - Gas Segment**                                   |       | **Derivative**                       |       | **2009**                                                | ** **   | **2008** | ** ** | **2009** | ** ** | **2008** | ** ** | **2009** | ** ** | **2008** |   |
| Commodity contracts                                            |       | Regulatory  (assets)/liabilities     |       | $                                                       |  77     |   | $ |  (395 | ) | $ |  (1,761 | ) | $ |  (71 | ) | $ |  (8,210 | ) | $ |  (1,262 | ) |
| ** **                                                     | ** ** | ** **                           |       |                                                    |         |   |   |   |   |   |   |   |   |   |   |
| **Total - Gas Segment**                                        | ** ** | ** **                           | ** ** | **$**                                                   | ** 77** | ** ** | **$** | ** (395** | **)** | **$** | ** (1,761** | **)** | **$** | ** (71** | **)** | **$** | ** (8,210** | **)** | **$** | ** (1,262** | **)** |

 

*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, 2009 is$3.8 million 

 

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for which we have posted no collateral in the normalcourse of business. If the credit-risk-related contingent features underlyingthese agreements were triggered on June 30, 2009, we would have beenrequired to post $1.8 million of collateral with one of our counterparties. On June 30,2009, we had no collateral posted with this counterparty.

 

**Note 5—Fair Value Measurements**

 

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

 

                FAS 157 also requires that thefair value measurement of assets and liabilities reflect the nonperformancerisk of counterparties and the reporting entity, as applicable. Therefore,using credit default spreads, we factored the impact of our own credit standingand the credit standing of our counterparties, as well as any potential creditenhancements (e.g. collateral) into the consideration of nonperformance riskfor both derivative assets and liabilities. The results of this analysis werenot material to the financial statements.

 

                The following fair valuehierarchy table presents information about our assets measured at fair valueusing the market value approach on a recurring basis as of June 30, 2009(in thousands):

 
| ** **                           | ** ** | ** **                              | ** **   | **Fair Value Measurements Using**                                       | ** ** |
|--------------------------------------|------------|-----------------------------------------|--------------|-------------------------------------------------------------------------|------------|
| **Description**                      | ** ** | **Assets/(Liabilities)  at Fair Value** | ** **   | **Quoted Prices in   Active Markets for   Identical Assets  (Level 1)** | ** ** | **Significant Other   Observable  Inputs  (Level 2)** | ** ** | **Significant   Unobservable   Inputs  (Level 3)** | ** ** |
| ** **                           | ** ** | **June 30,  2009**                 | ** **   |
| Net  derivative assets/(liabilities) |       | $                                       |  (4,070 | )                                                                       | $          |  (7,602 | ) | $ |  — |   | $ |  3,532 |   |
|                                 |       |                                    |         |                                                                    |       |   |   |   |   |
|                                 | ** ** | **December 31,  2008**             | ** **   |
| Net  derivative assets/(liabilities) |       | $                                       |  (6,749 | )                                                                       | $          |  (14,117 | ) | $ |  1,160 |   | $ |  6,208 |   |

 

                The following tables present thenet fair value on a recurring basis using significant unobservable inputs(Level 3) during the periods ended June 30, 2009 and 2008 (in thousands):

 

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

 
| **($ in 000’s)**                                                   | ** ** | **Net Derivatives(1)** | ** **  |
|------------------------------------------------------------------------------|------------|------------------------|-------------|
| Beginning  Balance, March 31, 2009                                      |       | $                      |  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                                         |       | (1,232                 | )           |
| Ending  Balance, June 30, 2009                                          |       | $                      |  3,532 |   |
|                                                                         |       |                   |        |
| Changes  in unrealized gains relating to assets still held at reporting date |       | $                      |  1,012 |   |

 

----

(1)          Net derivatives at June 30,2009 included derivative assets of $3.5 million and no derivative liabilities.

 

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| **($ in 000’s)**                                                   | ** ** | **Net Derivatives(1)** | ** **   |
|------------------------------------------------------------------------------|------------|------------------------|--------------|
| Beginning  Balance, March 31, 2008                                      |       | $                      |  12,266 |   |
| Total  gains or (losses) (realized/unrealized)                               |       |                   |         |
| Included  in earnings (or changes in net assets)                             |       | —                 |         |
| Included  in comprehensive income                                            |       | 9,807                  |         |
| Purchases,  issuances, and settlements                                       |       | —                 |         |
| Transfers  into and (out of) Level 3                                         |       | —                 |         |
| Ending  Balance, June 30, 2008                                          |       | $                      |  22,073 |   |
|                                                                         |       |                   |         |
| Changes  in unrealized gains relating to assets still held at reporting date |       | $                      |  9,807  |   |

 

----

(1) Netderivatives at June 30, 2008 included derivative assets of $22.1 millionand no derivative liabilities.

 

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

 
| **($ in 000’s)**                                                            | ** ** | **Net Derivatives(1)** | ** **   |
|---------------------------------------------------------------------------------------|------------|------------------------|--------------|
| Beginning  Balance, December 31, 2008                                            |       | $                      |  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                                                  |       | (1,232                 | )            |
| Ending  Balance, June 30, 2009                                                   |       | $                      |  3,532  |   |
|                                                                                  |       |                   |         |
| Changes  in unrealized gains/(losses) relating to assets still held at reporting date |       | $                      |  (1,444 | ) |

 

----

(1) Netderivatives at June 30, 2009 included derivative assets of $3.5 million andno derivative liabilities.

 
| **($ in 000’s)**                                                   | ** ** | **Net Derivatives(1)** | ** **   |
|------------------------------------------------------------------------------|------------|------------------------|--------------|
| Beginning  Balance, December 31, 2007                                   |       | $                      |  11,961 |   |
| Total  gains or (losses) (realized/unrealized)                               |       |                   |         |
| Included  in earnings (or changes in net assets)                             |       | —                 |         |
| Included  in comprehensive income                                            |       | 10,112                 |         |
| Purchases,  issuances, and settlements                                       |       | —                 |         |
| Transfers  into and (out of) Level 3                                         |       | —                 |         |
| Ending  Balance, June 30, 2008                                          |       | $                      |  22,073 |   |
|                                                                         |       |                   |         |
| Changes  in unrealized gains relating to assets still held at reporting date |       | $                      |  10,112 |   |

 

----

(1) Netderivatives at June 30, 2008 included derivative assets of $22.1 millionand no derivative liabilities.

 

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

 
| **($ in 000’s)**                                                            | ** ** | **Net Derivatives(1)** | ** **    |
|---------------------------------------------------------------------------------------|------------|------------------------|---------------|
| Beginning  Balance, June 30, 2008                                                |       | $                      |  22,073  |   |
| Total  gains or (losses) (realized/unrealized)                                        |       |                   |          |
| Included  in earnings (or changes in net assets)                                      |       | —                 |          |
| Included  in comprehensive income                                                     |       | (17,309                | )             |
| Purchases,  issuances, and settlements                                                |       | —                 |          |
| Transfers  into and (out of) Level 3                                                  |       | (1,232                 | )             |
| Ending  Balance, June 30, 2009                                                   |       | $                      |  3,532   |   |
|                                                                                  |       |                   |          |
| Changes  in unrealized gains/(losses) relating to assets still held at reporting date |       | $                      |  (17,309 | ) |

 

----

(1) Netderivatives at June 30, 2009 included derivative assets of $3.5 millionand no derivative liabilities.

 
| **($ in 000’s)**                                                   | ** ** | **Net Derivatives(1)** | ** **   |
|------------------------------------------------------------------------------|------------|------------------------|--------------|
| Beginning  Balance, June 30, 2007                                       |       | $                      |  11,455 |   |
| Total  gains or (losses) (realized/unrealized)                               |       |                   |         |
| Included  in earnings (or changes in net assets)                             |       | —                 |         |
| Included  in comprehensive income                                            |       | 10,618                 |         |
| Purchases,  issuances, and settlements                                       |       | —                 |         |
| Transfers  into and (out of) Level 3                                         |       | —                 |         |
| Ending  Balance, June 30, 2008                                          |       | $                      |  22,073 |   |
|                                                                         |       |                   |         |
| Changes  in unrealized gains relating to assets still held at reporting date |       | $                      |  10,618 |   |

 

----

(1) Netderivatives at June 30, 2008 included derivative assets of $22.1 millionand no derivative liabilities.

 

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*Long-Term Debt*

 

                The carrying amount of our totaldebt exclusive of capital leases at June 30, 2009, was $708 millioncompared to a fair market value of approximately $680 million. These estimateswere based on the quoted market prices for the same or similar issues or on thecurrent rates offered to us for debt of the same remaining maturities. Theestimated fair market value may not represent the actual value that could havebeen realized as of June 30, 2009 or that will be realizable in thefuture.

 

**Note 6— Financing**

 

                On March 27, 2009, weissued $75 million principal amount of 7% first mortgage bonds due April 1,2024. The net proceeds (after payment of expenses) of approximately $72.6 million were used to repayshort-term debt incurred, in part, to fund our current construction program.

 

                On February 25, 2009, weentered into an equity distribution agreement with UBS Securities LLC (UBS).Under the terms of the agreement, we may offer and sell shares of our commonstock, par value $1.00 per share, having an aggregate offering price of up to$60 million from time to time through UBS, as sales agent. We intend to use thenet proceeds from this equity distribution program to repay short-term debt andfor general corporate purposes, including to fund our current constructionprogram. During the second quarter of 2009, we issued and sold 6,400 sharespursuant to this equity distribution program, at an average price per share of$16.50, resulting in proceeds to us of approximately $0.1 million (afterpayment of approximately $4,489 in commissions to the sales agent). Through July 31,2009, in the aggregate, we have issued and sold 200,519 shares pursuant to theprogram, resulting in net proceeds to us of approximately $3.2 million.

 

                Sales of the shares pursuant to the equitydistribution agreement will be made at market prices or as otherwise agreedwith UBS. Under the terms of the program agreement, we may also sell shares toUBS as principal for UBS’ own account at a price agreed upon at the time ofsale.

 

                On March 11, 2009, weentered into a $50 million unsecured credit agreement. This agreement providesfor $50 million of revolving loans to be available to us for working capital,general corporate purposes and to back-up our use of commercial paper andterminates on July 15, 2010. This credit agreement is in addition to, andhas substantially identical covenants and terms as (other than pricing), ourAmended and Restated Unsecured Credit Agreement dated March 14, 2006discussed below. There were no borrowings under this agreement at June 30,2009.

 

                On July 15, 2005, weentered into a $150 million unsecured revolving credit facility until July 15,2010. Borrowings (other than through commercial paper) are at the bank’s primecommercial rate or LIBOR plus 100 basis points based on our current creditratings and the pricing schedule in the line of credit facility. On March 14,2006, we entered into the First Amended and Restated Unsecured Credit Agreementwhich amends and restates the $150 million unsecured revolving credit facility.The principal amount of the credit facility was increased to $226 million, withthe additional $76 million allocated to support a letter of credit issued inconnection with our participation in the Plum Point Energy Station project.This extra $76 million of availability reduces over a four year period in linewith the amount of construction expenditures we owe for Plum Point Unit 1 andwas $12.5 million as of August 1, 2009. The unallocated credit facility isused for working capital, general corporate purposes and to back-up our use ofcommercial paper. This facility requires our total indebtedness (which does notinclude our note payable to the securitization trust) to be less than 62.5% ofour total capitalization at the end of each fiscal quarter and our EBITDA(defined as net income plus interest, taxes, depreciation and amortization) tobe at least two times our interest charges (which includes interest on the notepayable to the securitization trust) for the trailing four fiscal quarters atthe end of each fiscal quarter. Failure to maintain these ratios will result inan event of default under the credit facility and will prohibit us fromborrowing funds thereunder. As of June 30, 2009, we are in compliance withthese ratios. This credit facility is also subject to cross-default if wedefault on in excess of $10 million in the aggregate on our other indebtedness.This arrangement does not serve to legally restrict the use of our cash in thenormal course of operations. There were $51.0 million of outstanding borrowingsunder this agreement at June 30, 

 

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2009.In addition, $21.0 million of the availability thereunder was used at such dateto back up our outstanding commercial paper.

 

**Note 7— Commitments and Contingencies**

 

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

 

**Coal,Natural Gas and Transportation Contracts**

 

                We have entered into long andshort-term agreements to purchase coal and natural gas for our energy supplyand natural gas operations. Certain of these are firm physical contracts andothers are derivatives that are used to hedge future purchases. Under thesecontracts, the natural gas supplies are divided into firm physical commitmentsand derivatives that are used to hedge future purchases. In the event that thisgas cannot be used, the gas would remain in storage or be liquidated at marketprice. The firm physical gas and transportation commitments are as follows (inmillions):

 
| Firm physical gas  and transportation contracts | ** ** | ** ** | ** ** |
|-------------------------------------------------|------------|------------|------------|
|                                            |       |       |       |
| July 1, 2009 through June 30, 2010    |       | $          |  41.5 |   |
| July 1, 2010 through June 30, 2012    |       | 65.2       |       |
| July 1, 2012 through June 30, 2014    |       | 42.7       |       |
| July 1, 2014 and beyond                    |       | 43.9       |       |
|                                                 |            |            |            |  |

 

                We have coal supply agreementsand transportation contracts in place to provide for the delivery of coal tothe plants. Some of these contracts  aresubject to fuel and index price adjustments. These contracts are written withForce Majeure clauses that enable us to reduce tonnages or cease shipments undercertain circumstances or events. These include mechanical or electricalmaintenance items, acts of God, war or insurrection, strikes, weather and otherdisrupting events. This reduces the risk we have for not taking the minimumrequirements of fuel under the contracts. Due to damage incurred in March 2009to our Asbury rail car unloading facility, we issued Force Majeure notices toour western coal suppliers and to the railroads, suspending western coalshipments. This relieved us of our contractual obligations to receive shipmentsof coal until the railroad unloading facility was repaired and put back inservice on May 13, 2009. The minimum requirements for our coal and coaltransportation contracts are as follows (in millions):

 
| Coal and coal  transportation contracts      |   |   |       |
|----------------------------------------------|--------|--------|------------|
|                                         |   |   |       |
| July 1, 2009 through June 30, 2010 |   | $      |  30.2 |   |
| July 1, 2010 through June 30, 2012 |   | 20.6   |       |
| July 1, 2012 through June 30, 2013 |   | 7.3    |       |
|                                              |        |        |            |  |

 

**Purchased Power**

 

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

 

                We have contracted with WestarEnergy for the purchase of capacity and energy through May 31, 2010.Commitments under this contract total approximately $14.8 million through May 31,2010.

 

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

 

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

 

**New Construction**

 

                On March 14, 2006, weentered into contracts to purchase an undivided interest in 50 megawatts of thePlum Point Energy Station’s new 665-megawatt, coal-fired generating facilitywhich is being built near Osceola, Arkansas. Dynegy reports that substantialcompletion is scheduled for the summer of 2010. The estimated cost is approximately$88.0 million, excluding allowance for funds used during construction (AFUDC).Our share of the Plum Point costs through June 30, 2009 was $79.3 million.

 

                On June 13, 2006, weannounced we had entered into an agreement with Kansas City Power &Light (KCP&L) to purchase an undivided ownership interest in the coal-firedIatan 2 generating facility. We will own 12%, or approximately 100 megawatts,of the 850-megawatt unit. Early in the third quarter of 2009, KCP&Lannounced its efforts to produce a cost and schedule reforecast primarily toaddress on-going productivity issues that were negatively impacting theoriginal schedule. KCP&L now reports that the anticipated in-service datefor Iatan 2 is late summer of 2010. Based on a late summer in-service date, weexpect base rates reflecting our investment to be in effect in early 2011**.** Our share of the Iatan 2 construction costs is stillexpected to be in a range of approximately $218 million to $230 million. Ourshare of the Iatan 2 costs through June 30, 2009 was $161.0 million. As arequirement for the air permit for Iatan 2, and to help meet requirements ofthe Clean Air Interstate Rule (CAIR), additional emission controlequipment was required for Iatan 1. Our share of the Iatan 1 environmentalcosts was $51.7 million through June 30, 2009. KCP&L reported theequipment had met regulatory in-service criteria as of April 19, 2009 andit is currently in service. All of these construction expenditures excludeAFUDC.

 

                There are risks that actualcosts may exceed budget estimates, delays may occur in obtaining permits andmaterials, suppliers and contractors may not perform as required under theircontracts, there may be inadequate availability, productivity or increased costof qualified craft labor, start-up activities may take longer than currentlyplanned, the scope and timing of projects may change, the re-baselined schedulemay not be met and other events beyond our control, including the failure ofone or more of the generation plant co-owners to pay their share ofconstruction, operations and maintenance costs, may occur that may materially affectthe schedule, budget, cost and performance of these projects. To the extent thecompletion of these projects is delayed, we expect that the timing of receipt ofincreases in base rates reflecting our investment in such projects will becorrespondingly delayed.

 

**Leases**

 

                As discussed above, on June 25,2007, we entered into a 20-year purchased power agreement with Cloud CountyWindfarm, LLC, owned by Horizon Wind Energy, Houston, Texas. Pursuant to theterms of the agreement, we will purchase all of the output from theapproximately 

 

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105-megawattPhase 1 Meridian Way Wind Farm located in Cloud County, Kansas. We do not ownany portion of the windfarm. Annual payments are contingent upon output of thefacility and can range from zero to a maximum of approximately $14.6 millionbased on a 20-year average cost.

 

                On December 10, 2004, weentered into a 20-year contract with Elk River Windfarm, LLC to purchase theenergy generated at the 150-megawatt Elk River Windfarm located in ButlerCounty, Kansas. We have contracted to purchase approximately 550,000megawatt-hours of energy per year, or approximately 10% of our annual supplyunder the contract. We do not own any portion of the windfarm. Payments forwind energy from the Elk River Windfarm are contingent upon output of the facility.Annual payments can run from zero to a maximum of approximately $16.9 millionbased on a 20-year average cost.

 

                Payments for these agreementsare recorded as purchased power expenses, and, because of the contingent natureof these payments, are not included in operating lease obligations.

 

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

 

                Ourlease obligations over the next five years have not significantlychanged at June 30, 2009, compared to December 31, 2008.

 

**Environmental Matters**

 

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

 

***Electric Segment***

 

*Air.* The 1990Amendments to the Clean Air Act, referred to as the 1990 Amendments, affect theAsbury, Riverton, State Line and Iatan 1 Power Plants and Units 3 and 4 (theFT8 peaking units) at the Empire Energy Center. The 1990 Amendments requireaffected plants to meet certain emission standards, including maximum emissionlevels for sulfur dioxide (SO2) and nitrogen oxides (NOx).

 

SO2Emissions.  Under the1990 Amendments, the amount of SO2 an affected unit can emit is regulated. Eachexisting affected unit has been allocated a specific number of emissionallowances, each of which allows the holder to emit one ton of SO2. Utilitiescovered by the 1990 Amendments must have emission allowances equal to thenumber of tons of SO2 emitted during a given year by each of their affectedunits. The annual reconciliation of allowances, which occurs on a facility widebasis, is held each March 1 for the previous calendar year. Allowances maybe traded between plants****or utilitiesor “banked” for future use. A market for the trading of emission allowancesexists on the Chicago Board of Trade. The Environmental****ProtectionAgency****(EPA) withholdsannually a percentage of the emission allowances allocated to each affectedunit and sells those emission allowances through a direct auction. We receivecompensation from the EPA for the sale of these withheld allowances. During2008 and 2009, we received less than $0.1 million from the EPA auction.

 

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

 

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17,394banked SO2 allowances as compared to 23,800 at March 1, 2008. We projectthat our 2009 emissions will again exceed the number of allowances allocated bythe EPA by an amount approximately equal to the difference during 2008.

 

                When our SO2 allowance bank isexhausted, currently estimated to be mid-2011, we will need to purchaseadditional SO2 allowances or build a Flue Gas Desulphurization (FGD) scrubbersystem at our Asbury Plant. Based on current and projected SO2 allowance pricesand high-level estimated FGD scrubber construction costs ($81 million in 2010dollars), we project it will be more economical for us to purchase SO2allowances than to build a scrubber at the Asbury Plant. Based on SO2 allowancemarket prices as of May 4, 2009 in conjunction with currently estimatedfuture operating parameters at the Asbury Plant, we estimate it will cost usapproximately $0.4 million to purchase SO2 allowances for the remainder of 2011and a range of approximately $0.45 million to $0.75 million annually for theyears 2012 through 2018. We would expect the costs of SO2 allowances to befully recoverable in our rates.

 

                Effective March 1, 2005,the MPSC approved a Stipulation and Agreement granting us authority to manageour SO2 allowance inventory in accordance with our SO2 Allowance ManagementPolicy (SAMP). The SAMP allows us to exchange banked allowances for futurevintage allowances and/or monetary value and, in extreme market conditions, tosell SO2 allowances outright for monetary value. We have not yet exchanged orsold any allowances under the SAMP.

 

                SO2 emissions will be furtherregulated as described in the Clean Air Interstate Rule section below.

 

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

 

                In March 2008, the EPAlowered the National Ambient Air Quality Standard (NAAQS) for ozone from 84 ppbto 75 ppb. Ozone, also called ground level smog, is formed by the mixing of NOxand****VolatileOrganic Compounds (VOCs) in the presence of sunlight. It is possible thatseveral counties in southwest Missouri will be classified as being innon-attainment of the ozone NAAQS standard by the EPA in 2010 or later. Weanticipate that the EPA will classify the Kansas City area, where Iatan 1 islocated, as being in non-attainment in 2010. At this time we do not foresee theneed for additional pollution controls due to the reduction in the ozonestandard. In addition, our units do not emit appreciable VOCs. We do notanticipate that southeast Kansas, where our Riverton Plant is located, will beclassified as non-attainment under the new ozone NAAQS.

 

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

 

Clean Air Interstate Rule (CAIR)

 

                The EPA issued its final CAIR onMarch 10, 2005. CAIR governed NOx and SO2 emissions from fossil fueledunits greater than 25 megawatts in 28 states, including Missouri, where ourAsbury, Energy Center, State Line and Iatan Units No. 1 and No. 2 arelocated and Arkansas where the Plum Point Energy Station is being constructed.Kansas was not included in CAIR and our Riverton Plant was not affected.

 

                On July 11, 2008, the U.S.Court of Appeals for the District of Columbia Circuit vacated the CAIR Rule andremanded it back to the EPA. However, the court stayed its vacatur on December 23,2008. As a result, CAIR became effective for NOx on January 1, 2009 andwill become effective for SO2 on January 1, 2010.

 

                TheCAIR is not directed to specific generation units, but instead, requires thestates (including Missouri and Arkansas) to develop State Implementation Plans(SIPs) to comply with specific NOx and SO2 state-wide annual budgets. Missouriand Arkansas finalized their respective regulations and submitted their SIPs tothe EPA, which were approved. We have received our full allotment of allowancesas published in the Missouri CAIR Rule. In addition to this allotment, theMissouri Department of Natural Resources (MDNR) has allocated 61 annual NOxallowances for 2009 to our account from the Renewable Energy Pool and weestimate we will be allocated an 

 

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additional 663 annual NOx allowances for 2009from the Compliance Supplemental Pool in 2010. Under the Arkansas CAIR rule, wewill not receive allowances until approximately six years after Plum Point Unit1 is operational. In the interim, we will transfer allowances from our Missouriunits. Based on SIPs for Missouri and Arkansas, we believe we will have excessannual and ozone season NOx allowances. SO2 allowances must be utilized at a2:1 ratio for our Missouri units as compared to our non-CAIR Kansas unitsbeginning in 2010. As a result, based on current SO2 allowance usageprojections, we expect to exhaust our banked allowances by mid-2011 and willneed to purchase additional SO2 allowances or build a scrubber at our AsburyPlant.

 

                Inorder to meet CAIR requirements for Iatan 1 and to meet air permit requirementsfor Iatan 2, pollution control equipment has been installed on Iatan 1.Installation was completed in April 2009 and KCP&L reported theequipment met in-service criteria as of April 19, 2009. This equipmentincludes a Selective Catalytic Reduction (SCR) system, an FGD scrubber and abaghouse, with our share of the capital cost estimated to be between $58million and $60 million, excluding AFUDC. Of this amount, approximately $3.9million was incurred in 2006, $12.1 million in 2007 and $27.3 million in 2008with estimated expenditures of approximately $15.6 million in 2009 (of which$8.4 million has been incurred through June 30, 2009). KCP&L is in theprocess of closing out the project and expects final costs by the end of theyear. This project was also included as part of our Experimental RegulatoryPlan approved by the MPSC.

 

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

 

AirPermits.**Under Title V of the 1990 Amendments,we must obtain site operating permits for each of our plants from theauthorities in the state in which the plant is located. These permits, whichare valid for five years, regulate the plant site’s total air emissions;including emissions from stacks, individual pieces of equipment, road dust,coal dust and other emissions. We have been issued permits for Asbury, Iatan,Riverton, State Line and the Energy Center Plants. We submitted the requiredrenewal applications for the State Line and Energy Center Title V permits in2003 and the Asbury Title V permit in 2004 and will operate under the existingpermits until the MDNR issues the renewed permits. A Compliance AssuranceMonitoring (CAM) plan for particulate matter (PM) will be required by therenewed permit for Asbury. We estimate that the capital costs associated with thePM CAM plan will not exceed $2 million. We submitted the renewal applicationfor the Riverton Title V permit in June 2008. A CAM plan for PM will alsobe required by the renewed permit for Riverton. No additional capital costs areanticipated. It is expected that the Kansas Department of Health andEnvironment (KDHE) will issue the renewal permit for Riverton in the thirdquarter of 2009.

 

                A new air permit was issued forthe Iatan Generating Station on January 31, 2006. The new permit coversthe entire Iatan Generating Station and includes the existing Unit No. 1and Iatan Unit No. 2 currently under construction. The Unit No. 1SCR, scrubber and baghouse are fully operational and the unit is operating incompliance with the permit conditions.

 

                The Clean Air Act requiredcompanies to obtain permits and, if necessary, install control equipment toreduce emissions when making a major modification or a change in operation ifeither is expected to cause a significant net increase in regulated emissions.The Sierra Club and Concerned Citizens of Platte County have claimed thatmodifications were made to Iatan 1 prior to the Comprehensive Energy Planproject in violation of Clean Air Act regulations. We own 12% of Iatan 1. Asoperator, KCP&L entered into a Collaboration Agreement with those partiesthat provide, among other things, for the release of such claims. In May 2008,a grand jury subpoena requesting documents was received by KCP&L. KCP&Lcompleted documentation delivery in response to the subpoena in March 2009.The outcome of these activities cannot presently be determined, nor can thecosts and other liabilities that could potentially result from a negativeoutcome presently be reasonably estimated.

 

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CleanAir Mercury Rule (CAMR)

 

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

 

                The EPA has not issued guidanceto the states regarding the vacated regulation nor recommended future actions.Based on CAMR, we installed a mercury analyzer at Asbury during late 2007 andinstalled two mercury analyzers at Riverton in 2008 in order to verify ourmercury emissions and to meet the monitoring compliance date of January 1,2009 and the Phase 1 mercury emission compliance date of January 1, 2010.We will operate the mercury analyzers at Riverton and Asbury in accordance withthe appropriate state environmental regulator’s guidance.

 

                The CAMR rulemaking was revokedby the EPA after final adjudication. Maximum Achievable Control Technology (MACT)re-emerged under current law but no specific MACT rulemakings have yet beenadopted in Missouri or Kansas.

 

CO2 Emissions

 

                Ourcoal and gas plants emit carbon dioxide (CO2), a greenhouse gas (GHG). Althoughnot currently regulated, increasing public concerns and political pressuresfrom local, regional, national and international bodies are likely to result inthe passage of new laws mandating limits on GHG emissions such as CO2. The EPArecently proposed a mandatory GHG reporting system to become effective in early2011 applicable to power generating and certain other facilities that exceedspecified emission thresholds. Also, in response to a 2007decision of the U.S. Supreme Court determining that GHG are air pollutantsunder the CAA, on April 17, 2009 the EPA proposed a finding that GHG,including CO2, threaten the public health and welfare. If finally adopted, thisendangerment finding by the EPA may lead it to promulgate regulations for GHGemissions, including those from power plants. On June 26, 2009, the U.S. House of Representatives passed theAmerican Clean Energy and Security Act of 2009 (also known as H.R. 2454). Thebill provides provisions to cap CO2 levels emitted by electric utilitiesat 3% below 2005 levels beginning in 2012. We are closely monitoring proposed CO2 legislation. Certain states havetaken steps to develop similar regulatory systems which may be more stringentthan any federal regulations. For example, Kansas is a participating member ofthe Midwestern Greenhouse Gas Reduction Accord, one purpose of which is todevelop a market-based cap and trade mechanism to reduce GHG emissions. Theimpact on us of any future GHG regulation will depend in large part on the detailsof the requirements and the timetable for mandatory compliance. Although therecan be no guarantee and the ultimate cost of any GHG regulations cannot bedetermined at this time, we would expect the cost of complying with any suchregulations to be fully recoverable in our rates. We also cannot predict withcertainty the impact to our financial position, liquidity or results ofoperations at this time.

 

*Water.* We operateunder the Kansas and Missouri Water Pollution Plans that were implemented inresponse to the Federal Water Pollution Control Act Amendments of 1972. TheAsbury, Iatan, Riverton, Energy Center and State Line plants are in compliancewith applicable regulations and have received discharge permits and subsequentrenewals as required.

 

                The Riverton Plant is affectedby final regulations for Cooling Water Intake Structures issued under the CleanWater Act (CWA) Section 316(b) Phase II. The regulations became finalon February 16, 2004 and required the submission of a Sampling Report andComprehensive Demonstration Study with the permit renewal in 2008. Sampling andsummary reports, which were completed during the first quarter of 2008 andsubmitted to the KDHE, indicate that the effect of the cooling water intakestructure on Empire Lake’s aquatic life is insignificant. The need for afurther Demonstration Study is not expected. On January 25, 2007, theUnited States Court of Appeals for the Second Circuit remanded key sections ofthese CWA regulations. On July 9,2007, the EPA suspended the regulation and is expected to revise and re-proposethe regulation in 2009. In

 

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addition, on April 14, 2008 certiorari wasgranted by the United States Supreme Court limited to the review as to whether Section 316(b) ofthe CWA authorized the EPA to compare costs with benefits in determining thebest technology available for minimizing adverse environmental impacts atcooling water intake structures. On April 1, 2009, the U.S. Supreme Courtoverturned the lower court’s ruling on the cost/benefit issue and remanded theregulation to the EPA. The permit renewal application was prepared andsubmitted in June 2008 and the final permit was received on January 1,2009. Under the initial regulations, we did not expect costs associated withcompliance to be material. We will reassess costs after the revised rules arecomplete.

 

*AshPonds.*We own and maintain coal ash ponds located at our Riverton and AsburyPower Plants. Additionally, we own a 12 percent interest in a coal ash pond atthe Iatan Generating Station. In April and May of 2009 we receivedInformation Collection Requests from the EPA regarding our ash ponds. Therequests were completed and submitted to the EPA as directed. All of the ashponds are compliant with state and federal regulations.

 

*RenewableEnergy.*On November 4, 2008, Missouri voters approvedthe Clean Energy Initiative (Proposition C). This initiative requiresinvestor-owned utilities in Missouri (such as Empire) to generate or purchaseelectricity from renewable energy sources, such as solar, wind, biomass andhydro power, at the rate of at least 2% in retail sales by 2011, increasing toat least 15% by 2021. At least 25 other states have adopted renewable portfoliostandard (RPS) programs that mandate some form of renewable generation. Some ofthese RPS programs incorporate a trading system in which utilities are allowedto buy and sell renewable energy certificates (RECs) in order to meetcompliance. Additionally, RECs are utilized by many companies in “green”marketing efforts. REC prices are driven by various market forces. We have beenselling RECs and plan to continue to sell all or a portion of the RECsassociated with our contracts with Elk River Windfarm, LLC and Cloud CountyWindfarm, LLC. With respect to the energy underlying the RECs that we sell, wemay not claim that we are purchasing renewable energy****for any purpose, includingfor purposes of complying with the new Missouri requirements. Over time, weexpect to retain some of the renewable attributes associated with thesecontracts in order to meet the new Missouri requirements. We realized revenuesof $1.8 million from REC sales in 2008 and $0.9 million in 2007. Revenues fromREC sales for the twelve months ended June 30, 2009 and 2008 were $1.5million and $1.4 million, respectively. Revenues from REC sales for the quarterended June 30, 2009 and 2008 were $0.3 million and $0.4 million,respectively and for the six months ended June 30, 2009 and 2008, RECrevenues were $0.7 million and $1.0 million, respectively.

 

TheMPSC initiated a proceeding on March 9, 2009 to develop a rulemaking toimplement Proposition C. The proceeding includes workshops and public commentperiods to allow for input from industry as well as the public at large. Weexpect this process to conclude in 2009.

 

***Gas Segment***

 

The acquisition of Missouri Gas involved theproperty transfer of two former manufactured gas plant (MGP) sites previouslyowned by Aquila, Inc. and its predecessors. Site #1 in Chillicothe,Missouri is listed in the MDNR Registry of Confirmed Abandoned or UncontrolledHazardous Waste Disposal Sites in Missouri. Site #2 in Marshall, Missouri hasreceived a letter of no further action from the MDNR. A Change of Use requestand work plan was approved by the MDNR allowing us to expand our existingservice center at Site #1 in Chillicothe, Missouri. This project, which wascompleted in October 2007, included the removal of all excavated soil andthe addition of a new concrete surface replacing the existing gravel at a costof approximately $0.1 million. We estimate further remediation costs at thesetwo sites to be no more than approximately $0.2 million, based on our bestestimate at this time. The remaining liability balance of $0.2 million isrecorded under noncurrent liabilities and deferred credits. In our agreementwith the MPSC approving the acquisition of Missouri Gas, it was agreed that wecould reflect a liability and offsetting regulatory asset not to exceed$260,000 for the acquired sites. The MPSC agreed that up to $260,000 of costsrelated to the clean up of these MGP sites would be allowed for future raterecovery. Accordingly, we concluded that rate recovery was probable and at theacquisition date, a regulatory asset of

 

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$260,000 was recorded as part of the purchase priceallocation based on our agreement with the MPSC, and in accordance with SFAS No. 71– “Accounting for the Effects of Certain Types of Regulation” (FAS 71).

 

**Note 8 – Retirement Benefits**

 

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

 
| ** **                                 | ** ** | **Three months ended June 30,**  | ** ** |
|--------------------------------------------|------------|---------------------------------------|------------|
| ** **                                 | ** ** | **Pension Benefits**                  | ** ** | **SERP** | ** ** | **OPEB** | ** ** |
| ** **                                 | ** ** | **2009**                              | ** ** | **2008** | ** ** | **2009** | ** ** | **2008** | ** ** | **2009** | ** ** | **2008** | ** ** |
| Service cost                               |       | $                                     | 1,019      |   | $ | 863 |   | $ | 15 |   | $ | 12 |   | $ | 509 |   | $ | 407 |   |
| Interest cost                              |       | 2,491                                 |       | 2,245 |   | 37 |   | 32 |   | 1,066 |   | 910 |   |
| Expected return on plan assets             |       | (2,601                                | )          | (2,680 | ) | — |   | — |   | (970 | ) | (938 | ) |
| Amortization of prior service cost **(1)** |       | 151                                   |       | 186 |   | (2 | ) | (2 | ) | (253 | ) | (253 | ) |
| Amortization of net actuarial loss **(1)** |       | 837                                   |       | 404 |   | 20 |   | 30 |   | 356 |   | 140 |   |
| **Net periodic benefit cost**              | ** ** | **$**                                 | **1,897**  | ** ** | **$** | **1,018** | ** ** | **$** | **70** | ** ** | **$** | **72** | ** ** | **$** | **708** | ** ** | **$** | **266** | ** ** |
| ** **                                 | ** ** | ** **                            | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| ** **                                 | ** ** | **Six months ended June 30,**    | ** ** |
| ** **                                 | ** ** | **Pension Benefits**                  | ** ** | **SERP** | ** ** | **OPEB** | ** ** |
| ** **                                 | ** ** | **2009**                              | ** ** | **2008** | ** ** | **2009** | ** ** | **2008** | ** ** | **2009** | ** ** | **2008** | ** ** |
| Service cost                               |       | $                                     | 2,010      |   | $ | 1,725 |   | $ | 31 |   | $ | 24 |   | $ | 963 |   | $ | 814 |   |
| Interest cost                              |       | 4,929                                 |       | 4,491 |   | 74 |   | 63 |   | 2,051 |   | 1,820 |   |
| Expected return on plan assets             |       | (5,202                                | )          | (5,359 | ) | — |   | — |   | (1,930 | ) | (1,876 | ) |
| Amortization of prior service cost **(1)** |       | 302                                   |       | 372 |   | (4 | ) | (4 | ) | (505 | ) | (505 | ) |
| Amortization of net actuarial loss **(1)** |       | 1,591                                 |       | 807 |   | 51 |   | 61 |   | 588 |   | 279 |   |
| **Net periodic benefit cost**              | ** ** | **$**                                 | **3,630**  | ** ** | **$** | **2,036** | ** ** | **$** | **152** | ** ** | **$** | **144** | ** ** | **$** | **1,167** | ** ** | **$** | **532** | ** ** |
| ** **                                 | ** ** | ** **                            | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| ** **                                 | ** ** | **Twelve months ended June 30,** | ** ** |
| ** **                                 | ** ** | **Pension Benefits**                  | ** ** | **SERP** | ** ** | **OPEB** | ** ** |
| ** **                                 | ** ** | **2009**                              | ** ** | **2008** | ** ** | **2009** | ** ** | **2008** | ** ** | **2009** | ** ** | **2008** | ** ** |
| Service cost                               |       | $                                     | 3,853      |   | $ | 3,468 |   | $ | 64 |   | $ | 49 |   | $ | 1,800 |   | $ | 1,468 |   |
| Interest cost                              |       | 9,486                                 |       | 8,641 |   | 147 |   | 122 |   | 3,848 |   | 3,287 |   |
| Expected return on plan assets             |       | (10,573                               | )          | (10,484 | ) | — |   | — |   | (3,804 | ) | (3,624 | ) |
| Amortization of prior service cost **(1)** |       | 674                                   |       | 772 |   | (8 | ) | (10 | ) | (1,011 | ) | (1,266 | ) |
| Amortization of net actuarial loss **(1)** |       | 2,477                                 |       | 2,108 |   | 123 |   | 134 |   | 820 |   | 831 |   |
| **Net periodic benefit cost**              | ** ** | **$**                                 | **5,917**  | ** ** | **$** | **4,505** | ** ** | **$** | **326** | ** ** | **$** | **295** | ** ** | **$** | **1,653** | ** ** | **$** | **696** | ** ** |

 

----

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

 

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

 

The expected minimum fundingfor 2009 is estimated to be between $1.9 million and $3.0 million. For 2010, itis estimated to be between $9.0 million and $15.0 million. The actual minimumfunding requirements will be determined based on the results of the actuarialvaluations and, in the case of 2010, the performance of our pension assetsduring 2009.

 

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

 

Werecognized the following amounts in compensation expense and tax benefits forall of our stock-based awards and programs for the applicable periods ended June 30(in thousands):

 
| ** **                 | ** ** | **Three Months Ended** | ** ** | **Six Months Ended** | ** ** | **Twelve Months Ended** | ** ** |
|----------------------------|------------|------------------------|------------|----------------------|------------|-------------------------|------------|
| ** **                 | ** ** | **2009**               | ** ** | **2008**             | ** ** | **2009**                | ** ** | **2008** | ** ** | **2009** | ** ** | **2008** | ** ** |
| **Compensation Expense**   |       | $                      | 669        |                 | $          | 503                     |       | $ | 1,248 |   | $ | 1,377 |   | $ | 1,712 |   | $ | 2,234 |   |
| **Tax Benefit Recognized** |       | 244                    |       | 181                  |       | 453                     |       | 505 |   | 607 |   | 813 |   |
|                            |            |                        |            |                      |            |                         |            |  |  |  |  |  |  |  |  |  |  |  |  |

 

28

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Activityfor our various stock plans for the six months ended June 30, 2009 issummarized below:

 

**Performance-Based Restricted Stock Awards**

 

The assumptions used in themodel for each grant year are noted in the following table:

 
| ** **                                  | ** ** | **Fair Value of Grants Outstanding at June 30,** | ** ** |
|---------------------------------------------|------------|-------------------------------------------------------|------------|
| ** **                                  | ** ** | **2009**                                              | ** ** | **2008** | ** ** |
| **Risk-free interest rate**                 |       | 0.35% to 1.37%                                        |       | 2.44% to 5.09% |   |
| **Expected volatility of Empire stock**     |       | 28.8%                                                 |       | 15.2% to 19.9% |   |
| **Expected volatility of peer group stock** |       | 21.8% to 79.6%                                        |       | 14.1% to 34.6% |   |
| **Expected dividend yield on Empire stock** |       | 7.3%                                                  |       | 5.4% to 5.8% |   |
| **Expected forfeiture rates**               |       | 3%                                                    |       | 3% |   |
| **Plan cycle**                              |       | 3 years                                               |       | 3 years |   |
| **Fair value percentage**                   |       | 105.0% to 130.0%                                      |       | 107.73% to  113.0% |   |
| **Weighted average fair value per share**   |       | $19.29                                                |       | $24.88 |   |

 

Non-vested restricted stockawards (based on target number) as of June 30, 2009 and 2008 and changesduring the six months ended June 30, 2009 and 2008 were as follows:

 
| ** **                       | ** ** | **2009**      | ** ** | **2008**             | ** ** |
|----------------------------------|------------|---------------|------------|----------------------|------------|
| ** **                       | ** ** | **Number**    | ** ** | **Weighted Average** | ** ** | **Number** | ** ** | **Weighted Average** | ** ** |
| ** **                       | ** ** | **of shares** | ** ** | **Grant Date Price** | ** ** | **of shares** | ** ** | **Grant Date Price** | ** ** |
| **Nonvested at January 1,** |       | 52,300        |       | $                    | 22.64      |   | 43,400 |   | $ | 23.02 |   |
| **Granted**                      |       | 13,500        |       | $                    | 18.12      |   | 21,000 |   | $ | 21.92 |   |
| **Awarded**                      |       | (12,394       | )          | $                    | 22.23      |   | (6,486 | ) | $ | 22.77 |   |
| **Not Awarded**                  |       | (1,206        | )          |                 |       | (5,614 | ) |   |   |
|                             |       |          |       |                 |       |   |   |   |   |
| **Nonvested at June 30,**   |       | 52,200        |       | $                    | 21.57      |   | 52,300 |   | $ | 22.64 |   |

 

At June 30, 2009, therewas $0.5 million of total unrecognized compensation cost related to estimatedoutstanding awards. This cost will be recognized over the outstanding yearsremaining in the vesting period.

 

**Stock Options**

 

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 30,2009 and 2008, under a Black-Scholes methodology. The assumptions used in thevaluations are shown below:

 
| ** **                                  | ** ** | **Fair Value of Grants Outstanding at June 30,** | ** ** |
|---------------------------------------------|------------|--------------------------------------------------|------------|
| ** **                                  | ** ** | **2009**                                         | ** ** | **2008** | ** ** |
| **Risk-free interest rate**                 |       | 1.25% to 2.97%                                   |       | 3.27% to 4.68% |   |
| **Dividend yield**                          |       | 7.3%                                             |       | 5.33% to 6.16% |   |
| **Expected volatility**                     |       | 24.0%                                            |       | 16.13% to 20.0% |   |
| **Expected life in months**                 |       | 78                                               |       | 60 to 78 |   |
| **Market value**                            |       | $16.52                                           |       | $20.25 |   |
| **Weighted average fair value per  option** |       | $0.63                                            |       | $2.21 |   |

 

Asummary of option activity under the plan during the six months ended June 30,2009 and 2008 is presented below:

 

29

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| ** **                         | ** ** | **2009**    | ** ** | **2008**             | ** ** |
|------------------------------------|------------|-------------|------------|----------------------|------------|
| ** **                         | ** ** | ** **  | ** ** | **Weighted Average** | ** ** | ** ** | ** ** | **Weighted Average** | ** ** |
| ** **                         | ** ** | **Options** | ** ** | **Exercise Price**   | ** ** | **Options** | ** ** | **Exercise Price** | ** ** |
| **Outstanding at January 1,** |       | 205,600     |       | $                    | 22.73      |   | 149,200 |   | $ | 23.04 |   |
| **Granted**                        |       | 27,000      |       | $                    | 18.12      |   | 56,400 |   | $ | 21.92 |   |
| **Exercised**                      |       | —      |       |                 |       | — |   |   |   |
| **Outstanding at June 30,**   |       | 232,600     |       | $                    | 22.19      |   | 205,600 |   | $ | 22.73 |   |
| **Exercisable at June 30,**   |       | 85,000      |       | $                    | 22.46      |   | 43,300 |   | $ | 22.67 |   |

 

Theaggregate intrinsic value at June 30, 2009 and 2008 was zero. Theintrinsic value of the unexercised options is the difference between Empire’sclosing stock price on the last day of the quarter and the exercise pricemultiplied by the number of in the money options had all option holdersexercised their option on the last day of the quarter. The intrinsic value iszero if such closing price is less than the exercise price.

 

Therange of exercise prices for the options outstanding at June 30, 2009 was$18.12 to $23.81. The weighted-average remaining contractual life ofoutstanding options at June 30, 2009 and 2008 was 7.1 years and 7.6 years,respectively. As of June 30, 2009, 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, 2009, there were 397,744 shares available forissuance in this plan.

 
| ** **                                     | ** ** | **2009** | ** ** | **2008** | ** ** |
|------------------------------------------------|------------|----------|------------|----------|------------|
| **Subscriptions outstanding at  June 30** |       | 69,830   |       | 49,960   |       |
| **Maximum subscription price**                 |       | $        | 14.62      |     | $          | 18.57 |   |
| **Shares of stock issued**(1)                  |       | 44,265   |       | 38,803   |       |
| **Stock issuance price**                       |       | $        | 14.10      |     | $          | 18.61 |   |

 

----

(1) Stockwill be issued on the closing date of the purchase period, which runs from June 1,2009 to May 31, 2010.

 

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

 
| ** **                                 | ** ** | **ESPP** | ** ** |
|--------------------------------------------|------------|----------|------------|
| ** **                                 | ** ** | **2009** | ** ** | **2008** | ** ** |
|                                       |       |     |       |   |   |
| **Weighted average fair value of  grants** |       | $        | 3.26       |   | $ | 3.46 |   |
| **Risk-free interest rate**                |       | 0.48     | %          | 2.17 | % |
| **Dividend yield**                         |       | 7.90     | %          | 6.20 | % |
| **Expected volatility**                    |       | 40.00    | %          | 26.00 | % |
| **Expected life in months**                |       | 12       |       | 12 |   |
| **Grant Date**                             |       | 6/1/09   |       | 6/2/08 |   |
|                                            |            |          |            |  |  |  |  |

 

**Note 10- Regulated Operating Expenses**

 

The following table sets forth the major components comprising “Regulatedoperating expenses” under “Operating Revenue Deductions” on our consolidatedstatements of operations (in thousands) for all periods presented ended June 30:

 

30

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| ** **                                         | ** ** | **Three  Months  Ended** | ** ** | **Three  Months  Ended** | ** ** | **Six  Months  Ended** | ** ** | **Six  Months  Ended** | ** ** | **Twelve  Months  Ended** | ** ** | **Twelve  Months  Ended** | ** ** |
|----------------------------------------------------|------------|--------------------------|------------|--------------------------|------------|------------------------|------------|------------------------|------------|---------------------------|------------|---------------------------|------------|
| ** **                                         | ** ** | **2009**                 | ** ** | **2008**                 | ** ** | **2009**               | ** ** | **2008**               | ** ** | **2009**                  | ** ** | **2008**                  | ** ** |
| Electric  transmission and distribution expense    |       | $                        | 2,747      |                     | $          | 2,687                  |       | $                      | 5,337      |                      | $          | 5,344                     |       | $ | 10,884 |   | $ | 10,432 |   |
| Natural  gas transmission and distribution expense |       | 548                      |       | 475                      |       | 1,074                  |       | 949                    |       | 2,119                     |       | 1,836                     |       |
| Power  operation expense (other than fuel)         |       | 3,062                    |       | 2,716                    |       | 6,126                  |       | 5,429                  |       | 12,369                    |       | 10,861                    |       |
| Customer  accounts and assistance expense          |       | 2,736                    |       | 2,439                    |       | 5,187                  |       | 4,987                  |       | 10,366                    |       | 9,845                     |       |
| Employee  pension expense (1)                      |       | 1,327                    |       | 1,568                    |       | 2,687                  |       | 3,122                  |       | 5,457                     |       | 6,285                     |       |
| Employee  healthcare plan (1)                      |       | 1,375                    |       | 1,944                    |       | 2,691                  |       | 3,887                  |       | 5,941                     |       | 7,581                     |       |
| General  office supplies and expense               |       | 2,564                    |       | 2,400                    |       | 4,824                  |       | 4,842                  |       | 9,312                     |       | 9,968                     |       |
| Administrative  and general expense                |       | 2,851                    |       | 2,529                    |       | 5,850                  |       | 5,487                  |       | 12,090                    |       | 10,871                    |       |
| Allowance  for uncollectible accounts              |       | 853                      |       | 879                      |       | 1,800                  |       | 1,450                  |       | 3,294                     |       | 3,456                     |       |
| Miscellaneous  expense                             |       | 13                       |       | 26                       |       | 1                      |       | 64                     |       | 102                       |       | 219                       |       |
| Total                                              |       | $                        | 18,076     |                     | $          | 17,663                 |       | $                      | 35,577     |                      | $          | 35,561                    |       | $ | 71,934 |   | $ | 71,354 |   |

 

----

(1) Includeseffects of regulatory treatment for pension and other postretirement benefitsbut does not include capitalized portion or amount deferred to a regulatoryasset.

 

**Note 11—Segment Information**

 

We operate our business as threesegments:  electric, gas and other. Aspart of our electric segment, we also provide water service to three towns inMissouri. The other segment consists of our non-regulated businesses, primarilya subsidiary for our fiber optics business.

 

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

 
| ** **                              | ** ** | **For the quarter ended 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 quarter ended June 30, 2008** | ** ** |
|-----------------------------------------|------------|----------------------------------------------|------------|
| **($-000’s)**                      | ** ** | **Electric**                                 | ** ** | **Gas** | ** ** | **Other** | ** ** | **Eliminations** | ** ** | **Total** | ** ** |
| **Statement of Operations Information** |       |                                         |       |   |   |   |   |   |   |   |   |
| Revenues                                |       | $                                            | 100,943    |   | $ | 9,148 |   | $ | 1,321 |   | $ | (132 | ) | $ | 111,280 |   |
| Depreciation  and amortization          |       | 13,055                                       |       | 481 |   | 326 |   | — |   | 13,862 |   |
| Federal  and state income taxes         |       | 2,467                                        |       | (403 | ) | 190 |   | — |   | 2,254 |   |
| Operating  income                       |       | 11,713                                       |       | 261 |   | 352 |   | — |   | 12,326 |   |
| Interest  income                        |       | 552                                          |       | 149 |   | — |   | (158 | ) | 543 |   |
| Interest  expense                       |       | 9,680                                        |       | 991 |   | 44 |   | (158 | ) | 10,557 |   |
| Income  from AFUDC (debt and equity)    |       | 3,011                                        |       | — |   | — |   | — |   | 3,011 |   |
| Net  income                             |       | 5,157                                        |       | (648 | ) | 308 |   | — |   | 4,817 |   |
| ** **                              |       |                                         |       |   |   |   |   |   |   |   |   |
| **Capital Expenditures**                |       | $                                            | 48,579     |   | $ | 453 |   | $ | 667 |   |   |   | $ | 49,699 |   |
|                                         |            |                                              |            |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

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

 
| ** **                              | ** ** | **For the six months ended June 30, 2008** | ** ** |
|-----------------------------------------|------------|-------------------------------------------------|------------|
| **($-000’s)**                      | ** ** | **Electric**                                    | ** ** | **Gas** | ** ** | **Other** | ** ** | **Eliminations** | ** ** | **Total** | ** ** |
| **Statement of Operations Information** |       |                                            |       |   |   |   |   |   |   |   |   |
| Revenues                                |       | $                                               | 209,682    |   | $ | 36,424 |   | $ | 2,382 |   | $ | (263 | ) | $ | 248,225 |   |
| Depreciation  and amortization          |       | 25,874                                          |       | 961 |   | 648 |   | — |   | 27,483 |   |
| Federal  and state income taxes         |       | 3,955                                           |       | 1,106 |   | 298 |   | — |   | 5,359 |   |
| Operating  income                       |       | 22,659                                          |       | 3,639 |   | 587 |   | — |   | 26,885 |   |
| Interest  income                        |       | 655                                             |       | 264 |   | — |   | (296 | ) | 623 |   |
| Interest  expense                       |       | 18,658                                          |       | 1,981 |   | 103 |   | (296 | ) | 20,446 |   |
| Income  from AFUDC (debt and equity)    |       | 5,476                                           |       | 1 |   | — |   | — |   | 5,477 |   |
| Net  income                             |       | 9,516                                           |       | 1,806 |   | 485 |   | — |   | 11,807 |   |
| ** **                              |       |                                            |       |   |   |   |   |   |   |   |   |
| **Capital Expenditures**                |       | $                                               | 102,826    |   | $ | 890 |   | $ | 1,082 |   |   |   | $ | 104,798 |   |
|                                         |            |                                                 |            |  |  |  |  |  |  |  |  |  |  |  |  |  |

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

 

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| ** **                              | ** ** | **For the twelve months ended June 30, 2008** | ** ** |
|-----------------------------------------|------------|----------------------------------------------------|------------|
| **($-000’s)**                      | ** ** | **Electric**                                       | ** ** | **Gas** | ** ** | **Other** | ** ** | **Eliminations** | ** ** | **Total** | ** ** |
| **Statement of Operations Information** |       |                                               |       |   |   |   |   |   |   |   |   |
| Revenues                                |       | $                                                  | 441,376    |   | $ | 60,273 |   | $ | 4,344 |   | $ | (507 | ) | $ | 505,486 |   |
| Depreciation  and amortization          |       | 51,147                                             |       | 1,912 |   | 1,243 |   | — |   | 54,302 |   |
| Federal  and state income taxes         |       | 13,739                                             |       | 1,095 |   | 559 |   | — |   | 15,393 |   |
| Operating  income                       |       | 59,904                                             |       | 5,626 |   | 885 |   | — |   | 66,415 |   |
| Interest  income                        |       | 695                                                |       | 454 |   | — |   | (381 | ) | 768 |   |
| Interest  expense                       |       | 37,166                                             |       | 3,974 |   | 17 |   | (381 | ) | 40,776 |   |
| Income  from AFUDC (debt and equity)    |       | 9,459                                              |       | 4 |   | — |   | — |   | 9,463 |   |
| Net  Income                             |       | 31,916                                             |       | 1,849 |   | 840 |   | — |   | 34,605 |   |
| ** **                              |       |                                               |       |   |   |   |   |   |   |   |   |
| **Capital Expenditures**                |       | $                                                  | 203,316    |   | $ | 2,180 |   | $ | 4,277 |   |   |   | $ | 209,773 |   |
|                                         |            |                                                    |            |  |  |  |  |  |  |  |  |  |  |  |  |  |

** **
| ** **                    | ** ** | **As of June 30, 2009** | ** ** |
|-------------------------------|------------|-------------------------|------------|
| **($-000’s)**            | ** ** | **Electric**            | ** ** | **Gas(1)** | ** ** | **Other** | ** ** | **Eliminations** | ** ** | **Total** | ** ** |
| **Balance Sheet Information** |       |                    |       |   |   |   |   |   |   |   |   |
| Total  assets                 |       | $                       | 1,681,351  |   | $ | 134,607 |   | $ | 22,186 |   | $ | (85,565 | ) | $ | 1,752,579 |   |
|                               |            |                         |            |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

----

(1) Includesgoodwill of $39,492.

 
| ** **                    | ** ** | **As of December 31, 2008** | ** ** |
|-------------------------------|------------|-----------------------------|------------|
| **($-000’s)**            | ** ** | **Electric**                | ** ** | **Gas(1)** | ** ** | **Other** | ** ** | **Eliminations** | ** ** | **Total** | ** ** |
| **Balance Sheet Information** |       |                        |       |   |   |   |   |   |   |   |   |
| Total  assets                 |       | $                           | 1,621,502  |   | $ | 138,788 |   | $ | 22,186 |   | $ | (68,630 | ) | $ | 1,713,846 |   |
|                               |            |                             |            |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

----

(1) Includesgoodwill of $39,492.

 

**Note 12—Income Taxes**

 

We adopted the provisions ofFASB Interpretation No. 48, “Accountingfor Uncertainty in**Income Taxes,”**on January 1, 2007. Wedecreased our estimate of unrecognized tax benefits by an immaterial amountduring the quarter ended March 31, 2008 as a review of certain amendedreturns by the Joint Committee on Taxation was completed. The Joint Committeeaccepted our tax position which led us to recognize certain tax benefitspreviously unrecognized. We do not expect any significant changes to ourunrecognized tax benefits over the next twelve months. The reserve balancerelated to unrecognized tax benefits as of December 31, 2008 was$2,176,000 and has not materially changed at June 30, 2009.

 

Ourconsolidated provision for income taxes increased approximately $2.1 millionduring the second quarter of 2009 as compared to the same period in 2008 mainlydue to increased income. Our consolidated effective federal and state incometax rate for the second quarter of 2009 was 34.7% as compared to 31.9% for thesecond quarter of 2008.

 

Ourconsolidated provision for income taxes increased approximately $4.5 millionduring the six months ended June 30, 2009 as compared to the same periodin 2008. This resulted primarily from increased income. Our consolidatedeffective federal and state income tax rate for the six months ended June 30,2009 was 34.2% as compared to 31.2% for the same period in 2008.

 

Ourconsolidated provision for income taxes increased approximately $8.5 millionduring the twelve months ended June 30, 2009 as compared to the twelvemonths ended June 30, 2008, primarily resulting from higher income. Oureffective federal and state income tax rate for the twelve months ended June 30,2009 was 33.5% as compared to 30.8% for the same period in 2008.

 

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Therates in all periods are higher when comparing to the corresponding priorperiod primarily due to lower tax benefits received from cost of plantretirement expenditures. Our cost of retirement expenditures was unusually highduring the twelve months ended June 30, 2008 due to the ice storms weexperienced. This reduced benefit during this period was partially offset by anincrease in the tax effects of equity AFUDC.

 

**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 non-regulated businesses, primarilya 100% interest in Empire District Industries, Inc., a subsidiary for ourfiber optics business. During the twelve months ended June 30 2009, 86.5%of our gross operating revenues were provided from sales from our electricsegment (including 0.3% from the sale of water), 12.6% from our gas segment and0.9% from our other segment.

 

***Earnings***

 

During the second quarter of 2009, basic anddiluted earnings per weighted average share of common stock were $0.22 ascompared to $0.14 in the second quarter of 2008. For the six months ended June 30,2009, basic and diluted earnings per weighted average share of common stockwere $0.54 as compared to $0.35 for the six months ended June 30, 2008.For the twelve months ended June 30, 2009, basic earnings per weightedaverage share of common stock were $1.37 as compared to $1.08 for the twelvemonths ended June 30, 2008 and diluted earnings per weighted average shareof common stock were $1.36 as compared to $1.08 for the twelve months ended June 30,2008. As reflected in the table below, the primary positive drivers for allperiods presented were increased revenues, mainly due to our 2008 Missouri ratecase, and decreased fuel and purchased power costs. The primary negativedrivers for all periods presented were increased maintenance costs anddecreased revenues due to decreased off-system sales.

 

The following reconciliation of basicearnings per share between the three months, six months and twelve months endedJune 30, 2008 versus June 30, 2009 is a non-GAAP presentation. Webelieve this information is useful in understanding the fluctuation in earningsper share between the prior and current years. The reconciliation presents theafter tax impact of significant items and components of the statement of operationson a per share basis before the impact of additional stock issuances which ispresented separately. Earnings per share for the three months, six months andtwelve months ended June 30, 2008 and 2009 shown in the reconciliation arepresented on a GAAP basis and are the same as the amounts included in thestatements of operations. This reconciliation may not be comparable to othercompanies or more useful than the GAAP presentation included in the statementsof operations.

 

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| ** **                                   | ** ** | **Three Months  Ended** | ** ** | **Six Months  Ended** | ** ** | **Twelve Months  Ended** | ** ** |
|----------------------------------------------|------------|-------------------------|------------|-----------------------|------------|--------------------------|------------|
| **Earnings Per Share – 2008**           | ** ** | **$**                   | **0.14**   | ** **            | **$**      | **0.35**                 | ** ** | **$** | **1.08** | ** ** |
| ** **                                   |       |                    |       |                  |       |                     |       |
| **Revenues**                                 |       |                    |       |                  |       |                     |       |
| Electric  on-system                          |       | $                       | 0.14       |                  | $          | 0.17                     |       | $ | 0.26 |   |
| Electric  off-system and other               |       | (0.10                   | )          | (0.16                 | )          | (0.11                    | )          |
| Gas                                          |       | (0.02                   | )          | (0.01                 | )          | 0.10                     |       |
| Other                                        |       | 0.00                    |       | 0.00                  |       | 0.02                     |       |
| **Expenses**                                 | ** ** | ** **              | ** ** | ** **            | ** ** | ** **               | ** ** |
| Electric  fuel and purchased power           |       | 0.11                    |       | 0.31                  |       | 0.41                     |       |
| Cost  of natural gas sold and transported    |       | 0.02                    |       | (0.01                 | )          | (0.13                    | )          |
| Regulated  **–** electric segment       |       | (0.01                   | )          | 0.01                  |       | 0.00                     |       |
| Regulated  **–**gas segment             |       | 0.00                    |       | (0.01                 | )          | (0.01                    | )          |
| Other  segment                               |       | 0.00                    |       | 0.00                  |       | (0.01                    | )          |
| Maintenance  and repairs                     |       | (0.04                   | )          | (0.08                 | )          | (0.11                    | )          |
| Depreciation  and amortization               |       | 0.02                    |       | 0.04                  |       | 0.06                     |       |
| Other  taxes                                 |       | (0.01                   | )          | (0.01                 | )          | (0.01                    | )          |
| Interest  charges                            |       | (0.02                   | )          | (0.06                 | )          | (0.11                    | )          |
| AFUDC                                        |       | 0.01                    |       | 0.03                  |       | 0.10                     |       |
| Gain  on sale of assets                      |       | —                  |       | —                |       | (0.03                    | )          |
| Change  in effective income tax rates        |       | (0.01                   | )          | (0.03                 | )          | (0.06                    | )          |
| Gain  on sale of land                        |       | 0.00                    |       | 0.01                  |       | 0.01                     |       |
| Other  income and deductions                 |       | (0.01                   | )          | (0.01                 | )          | (0.03                    | )          |
| Dilutive  effect of additional shares issued |       | 0.00                    |       | 0.00                  |       | (0.06                    | )          |
| **Earnings Per Share – 2009**           | ** ** | **$**                   | **0.22**   | ** **            | **$**      | **0.54**                 | ** ** | **$** | **1.37** | ** ** |

 

**RecentActivities**

 

***2009 Storm Damage***

 

A major wind storm caused substantial damage to our electric serviceterritory on May 8, 2009. Approximately 83,000 of our electric customerswere without power at the height of the storm.

 

Incremental costs associated with the restoration effort due to thewind storm were approximately $6.4 million, of which $5.7 million wascapitalized as additions to our utility plant and approximately $0.7 millionwas maintenance expense that was deferred as a regulatory asset as we believeit is probable that these costs will be recoverable in future electric ratecases.

 

***Ozark Beach Plant***

 

Ourhydroelectric generating plant (FERC Project No. 2221), located on theWhite River at Ozark Beach, Missouri, has a generating capacity of 16megawatts. We have a long-term license from FERC to operate this plant whichforms Lake Taneycomo in southwestern Missouri. As part of the Energy and WaterDevelopment Appropriations Act of 2006 (the Appropriations Act), a new minimumflow was established with the intent of increasing minimum flows onrecreational streams in Arkansas. To accomplish this, the level of Bull ShoalsLake will be increased an average of 5 feet. The increase at Bull Shoals willdecrease the head waters available for generation at Ozark Beach by 5 feet and,thus, reduce our electrical output. We estimate the lost production to be up to16% of our average annual energy production for this unit. The loss in thisfacility would require us to replace it with additional generation from ourgas-fired and coal-fired units or with purchased power. The Appropriations Acthas a provision for the Army Corp of Engineers to provide a one time payment tous for lost energy production. The Appropriations Act requires the SouthwestPower Administration (SWPA), in coordination with us and our relevant publicservice commissions, to determine our economic detriment. The SWPA publishedits Final Determination Report on January 23, 2009 documenting theprocedure they intended to use to calculate the present value of the futurelifetime replacement cost of the electrical energy and capacity lost due to theWhite River Minimum Flows project at Ozark Beach. The actual hydropowercompensation values were to be

 

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calculatedusing the method presented in the Final Determination and current values forthe specified parameters based on the official implementation date. Assuming a January 1,2011 date of 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 $41,319,400. However,on June 8, 2009, the SWPA published a draft addendum in the FederalRegister to its January 2009 Final Determination Report documentingproposed changes to the SWPA’s methodology. Assuming a January 1, 2011date of implementation for the White River Minimum Flows project and currentvalues for the specified parameters, the SWPA’s Draft Addendum to its FinalDetermination results in a present value of $22,340,800 for the estimatedfuture lifetime replacement costs of the electrical energy and capacity atOzark Beach. We and the MPSC have provided comments on the new methodologyincluded in the draft addendum but cannot predict the final outcome. We expectthat the Army Corp of Engineers will not implement the new minimum flow planuntil at least January 2011, but, at this time, we cannot be sure of thetimetable as it is dependent on Congress providing funding for the economicdetriment.

 

***SLCC Generator Failure***

 

OnJuly 3, 2009, the generator on State Line Unit 2-1, one of the combustionturbines at SLCC, failed during operation. Unit 2-1 represents about 150megawatts of the 500 megawatts rated output of SLCC,of which we are entitled to 60%, or 300megawatts. The remainder of SLCC is undamaged and continues to operate asnormal. However, since the SLCC consists of the combination of two combustionturbines, two heat recovery steam generators, a steam turbine and auxiliaryequipment, we cannot utilize the entire capability of the steam turbine withoutthe use of Unit 2-1. This reduces SLCC’s generation capability by another 100megawatts. Determinations as to the cost and timing of the repair have not yetbeen finalized. However, the damage is in excess of the $1.5 million insurancedeductible on the unit. At this point, we expect Unit 2-1 will return toservice during the fall of 2009. We do not anticipate the unplanned outage tohave a material financial impact.

 

***Regulatory Plan***

 

OnMay 1, 2009, we began recording deferred carrying charges associated withenvironmental upgrades recently completed at our Iatan 1 facility in accordancewith our regulatory plan. We deferred $0.8 million in the second quarter of2009. Construction accounting, for purposes of the regulatory plan, allows usto defer certain charges as regulatory assets, including depreciation andcarrying costs, related to operation of the facilities until the facilities areultimately included in our rate base. The amounts deferred, which began at thein-service date for Iatan 1 and will also be deferred for Iatan 2 at itsin-service date, will then be amortized over the life of the plants once theyare in our rate base. The regulatory plan covers the 150 megawatt V84.3A2combustion turbine (Unit 12) that began commercial operation on April 10,2007 at our Riverton plant, the environmental upgrades at Asbury, which werecompleted in 2008, environmental upgrades at Iatan 1 and the construction ofthe Iatan 2 facilities. See Note 3 of “Notes to Consolidated FinancialStatements (Unaudited)”.

 

***Regulatory Matters***

 

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 equity of11.3%. Results from this case would likely take effect in the second quarter of2010.

 

Allpending applications for rehearing in our 2006 Missouri electric rate case weredenied by the MPSC on November 20, 2008. On December 15, 2008, theOPC filed a Petition for Writ of Review with the Cole County Circuit Courtregarding the MPSC’s decisions in our 2006 rate case. Praxair and ExplorerPipeline filed a Petition for Writ of Review on December 19, 2008. These

 

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actionswere consolidated into one proceeding. Briefs have been filed by all partiesand oral argument took place on June 2, 2009.

 

OnMay 13, 2009, the OPC filed a petition in the Jasper County Circuit Courtseeking refunds with regard to utility rates for electric service paid by ourcustomers during the period of January 1, 2007 to December 13, 2007.During this period, we charged the rates set forth in the tariffs which wereapproved by, and are on file with, the MPSC. We filed a motion to dismiss, or,in the alternative, motion for more definitive statement. Oral argument on ourmotion is scheduled for August 28, 2009.

 

For additional information, see “Rate Matters”below.

 

***Financings***

 

OnFebruary 25, 2009, we entered into an equity distribution agreement withUBS Securities LLC (UBS). Under the terms of the agreement, we may offer andsell shares of our common stock, par value $1.00 per share, having an aggregateoffering price of up to $60 million from time to time through UBS, as salesagent. We intend to use the net proceeds from this equity distribution programto repay short-term debt and for general corporate purposes, including to fundour current construction program. During the second quarter of 2009, we issuedand sold 6,400 shares pursuant to this program, at an average price per shareof $16.50, resulting in proceeds to us of approximately $0.1 million (afterpayment of approximately $4,489 in commissions to the sales agent). Through July 31,2009, in the aggregate, we have issued and sold 200,519 shares pursuant to theprogram, resulting in net proceeds to us of approximately $3.2 million.

 

Sales of the shares pursuantto the equity distribution agreement will be made at market prices or asotherwise agreed with UBS. Under the terms of the program agreement, we mayalso sell shares to UBS as principal for UBS’ own account at a price agreedupon at the time of sale.

 

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.

 

OnMarch 11, 2009, we entered into a $50 million unsecured credit agreement.This agreement provides for $50 million of revolving loans to be available tous for working capital, general corporate purposes and to back-up our use ofcommercial paper and terminates on July 15, 2010. This credit agreement isin addition to, and has substantially identical covenants and terms as (otherthan pricing), our Amended and Restated Unsecured Credit Agreement dated March 14,2006. There were no borrowings under the new agreement at June 30, 2009.

 

**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 30,2009, compared to the same periods ended June 30, 2008.

 

The following table represents our results ofoperations by operating segment for the applicable periods ended June 30(in millions):

 
| ** **                           | ** ** | **Quarter Ended** | ** ** | **Six Months Ended** | ** ** | **Twelve Months Ended** | ** ** |
|--------------------------------------|------------|-------------------|------------|----------------------|------------|-------------------------|------------|
| ** **                           | ** ** | **2009**          | ** ** | **2008**             | ** ** | **2009**                | ** ** | **2008** | ** ** | **2009** | ** ** | **2008** | ** ** |
|                                 |       |              |       |                 |       |                    |       |   |   |   |   |   |   |
| Income  from continuing operations   |       |              |       |                 |       |                    |       |   |   |   |   |   |   |
| Electric                             |       | $                 | 8.0        |                 | $          | 5.2                     |       | $ | 16.8 |   | $ | 9.5 |   | $ | 44.8 |   | $ | 31.9 |   |
| Gas                                  |       | (0.8              | )          | (0.6                 | )          | 1.0                     |       | 1.8 |   | 0.9 |   | 1.8 |   |
| Other                                |       | 0.4               |       | 0.3                  |       | 0.7                     |       | 0.5 |   | 0.8 |   | 0.9 |   |
| Income  from continuing operations   |       | $                 | 7.6        |                 | $          | 4.8                     |       | $ | 18.5 |   | $ | 11.8 |   | $ | 46.5 |   | $ | 34.6 |   |
| Income  from discontinued operations |       | —            |       | —               |       | —                  |       | — |   | — |   | 0.1 |   |
| Net income                           |       | $                 | 7.6        |                 | $          | 4.8                     |       | $ | 18.5 |   | $ | 11.8 |   | $ | 46.5 |   | $ | 34.7 |   |

 

----

**Differences could occur due to rounding.*

 

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***Electric Segment***

 

**Overview**

 

Our electric segment income for the second quarter of 2009 was $8.0million as compared to $5.2 million for the second quarter of 2008.

 

Electric operating revenues comprised approximately 91.5% of our totaloperating revenues during the second quarter of 2009. Of our total electricoperating revenues during the second quarter of 2009, approximately 38.5% werefrom residential customers, 34.3% from commercial customers, 16.4% from industrialcustomers, 4.2% from wholesale on-system customers, 2.5% from wholesaleoff-system transactions, 2.7% from other electric revenues, primarily publicauthorities, and 1.4% from miscellaneous sources. The percentage of revenuesprovided from our wholesale off-system transactions decreased during the secondquarter of 2009 as compared to the second quarter of 2008, primarily due todecreased market demand resulting from milder weather in April and May of2009 and general economic conditions.

 

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**    | ** ** | **2009**          | ** ** | **2008** | ** ** | **Change*** | ** ** | **2009** | ** ** | **2008** | ** ** | **Change*** | ** ** | **2009** | ** ** | **2008** | ** ** | **Change*** | ** ** |
| Residential           |       | 387.2             |       | 381.6 |   | 1.5 | % | 938.1 |   | 975.1 |   | (3.8 | )% | 1,915.9 |   | 1,981.7 |   | (3.3 | )% |
| Commercial            |       | 403.9             |       | 392.5 |   | 2.9 |   | 779.9 |   | 771.4 |   | 1.1 |   | 1,630.5 |   | 1,626.1 |   | 0.3 |   |
| Industrial            |       | 252.0             |       | 269.5 |   | (6.5 | ) | 492.3 |   | 531.6 |   | (7.4 | ) | 1,034.0 |   | 1,097.0 |   | (5.7 | ) |
| Wholesale on-system   |       | 82.7              |       | 83.7 |   | (1.1 | ) | 163.5 |   | 169.1 |   | (3.3 | ) | 339.0 |   | 348.8 |   | (2.8 | ) |
| Other**               |       | 29.8              |       | 30.0 |   | (0.9 | ) | 62.0 |   | 62.0 |   | (0.1 | ) | 123.7 |   | 123.1 |   | 0.5 |   |
| Total on-system sales |       | 1,155.6           |       | 1,157.3 |   | (0.1 | ) | 2,435.8 |   | 2,509.2 |   | (2.9 | ) | 5,043.1 |   | 5,176.7 |   | (2.6 | ) |
| Off-system            |       | 111.9             |       | 169.4 |   | (34.0 | ) | 245.7 |   | 309.8 |   | (20.7 | ) | 624.1 |   | 572.5 |   | 9.0 |   |
| Total KWh Sales       |       | 1,267.5           |       | 1,326.7 |   | (4.5 | ) | 2,681.5 |   | 2,819.0 |   | (4.9 | ) | 5,667.2 |   | 5,749.2 |   | (1.4 | ) |

 

----

**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.*

 
| ** **                        | ** ** | **Electric Segment Operating Revenues** | ** ** |
|-----------------------------------|------------|-----------------------------------------|------------|
| ** **                        | ** ** | **($ in millions)**                | ** ** |
| ** **                        | ** ** | **Second**                              | ** ** | **Second** | ** ** | ** ** | ** ** | **6 Months** | ** ** | **6 Months** | ** ** | ** ** | ** ** | **12 Months** | ** ** | **12 Months** | ** ** | ** ** | ** ** |
| ** **                        | ** ** | **Quarter**                             | ** ** | **Quarter** | ** ** | **%** | ** ** | **Ended** | ** ** | **Ended** | ** ** | **%** | ** ** | **Ended** | ** ** | **Ended** | ** ** | **%** | ** ** |
| **Customer Class**                | ** ** | **2009**                                | ** ** | **2008** | ** ** | **Change*** | ** ** | **2009** | ** ** | **2008** | ** ** | **Change*** | ** ** | **2009** | ** ** | **2008** | ** ** | **Change*** | ** ** |
| Residential                       |       | $                                       | 39.5       |   | $ | 36.3 |   | 8.6 | % | $ | 88.1 |   | $ | 85.0 |   | 3.6 | % | $ | 182.4 |   | $ | 178.6 |   | 2.1 | % |
| Commercial                        |       | 35.3                                    |       | 31.7 |   | 11.3 |   | 64.9 |   | 59.6 |   | 9.0 |   | 138.2 |   | 130.3 |   | 6.1 |   |
| Industrial                        |       | 16.8                                    |       | 16.6 |   | 1.3 |   | 31.7 |   | 31.4 |   | 0.8 |   | 67.6 |   | 67.2 |   | 0.6 |   |
| Wholesale on-system               |       | 4.3                                     |       | 4.4 |   | (2.4 | ) | 9.0 |   | 9.5 |   | (5.0 | ) | 18.7 |   | 19.4 |   | (3.3 | ) |
| Other**                           |       | 2.7                                     |       | 2.6 |   | 5.2 |   | 5.5 |   | 5.2 |   | 6.4 |   | 11.4 |   | 10.7 |   | 6.6 |   |
| Total on-system revenues          |       | $                                       | 98.6       |   | $ | 91.6 |   | 7.6 |   | $ | 199.2 |   | $ | 190.7 |   | 4.5 |   | $ | 418.3 |   | $ | 406.2 |   | 3.0 |   |
| Off-system                        |       | 2.6                                     |       | 7.4 |   | (64.6 | ) | 6.6 |   | 14.8 |   | (55.6 | ) | 21.5 |   | 27.1 |   | (20.8 | ) |
| Total revenues from kWh sales     |       | 101.2                                   |       | 99.0 |   | 2.2 |   | 205.8 |   | 205.5 |   | 0.1 |   | 439.8 |   | 433.3 |   | 1.5 |   |
| Miscellaneous revenues***         |       | 1.4                                     |       | 1.5 |   | (5.0 | ) | 3.2 |   | 3.3 |   | (2.6 | ) | 6.9 |   | 6.2 |   | 10.5 |   |
| Total electric operating Revenues |       | $                                       | 102.6      |   | $ | 100.5 |   | 2.1 |   | $ | 209.0 |   | $ | 208.8 |   | 0.1 |   | $ | 446.7 |   | $ | 439.5 |   | 1.6 |   |
| Water revenues                    |       | 0.5                                     |       | 0.4 |   | (1.3 | ) | 0.9 |   | 0.9 |   | (2.0 | ) | 1.7 |   | 1.9 |   | (4.7 | ) |
| Total Electric Segment            |       |                                    |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Operating Revenues                |       | $                                       | 103.1      |   | $ | 100.9 |   | 2.1 |   | $ | 209.9 |   | $ | 209.7 |   | 0.1 |   | $ | 448.4 |   | $ | 441.4 |   | 1.6 |   |

 

----

**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, rent, etc.*

 

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***Quarter Ended June 30, 2009 Compared to QuarterEnded June 30, 2008***

 

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

 

KWh sales for our on-system customers decreased slightly during thesecond quarter of 2009 as compared to the second quarter of 2008. However,revenues for our on-system customers increased approximately $7.0 million, or7.6%, primarily due to the August 2008 Missouri rate increase (discussedbelow). Rate changes contributed an estimated $6.4 million of the increase inrevenues during the second quarter of 2009. Weather and other related factorsincreased revenues by an estimated $0.5 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 2009 were 21.7% morethan the same period last year and 16.6% more than the 30-year average, mainlydue to unseasonably hot weather in June of 2009. Residential andcommercial sales growth contributed an estimated $0.1 million of the increase inrevenues. Our electric customer growth for the twelve months ended June 30,2009 was 0.2%.

 

Residential and commercial kWh sales and related revenues increasedduring the second quarter of 2009 due to the favorable June 2009 weatherwhile revenues also increased due to the 2008 Missouri rate increase.

 

Industrial kWh sales decreased 6.5% mainly due to a slowdown created byeconomic uncertainty while the associated revenues increased 1.3% due to theeffects of the 2008 Missouri rate increase which offset the economicconditions.

 

On-system wholesale kWh sales decreased during the second quarter of2009 reflecting the general economic conditions. Revenues associated with theseFERC-regulated sales decreased more than kWh sales as a result of the fueladjustment clause applicable to such sales. This clause permits thedistribution to customers of changes in fuel and purchased power costs.

 

**Off-System Electric Transactions**

 

In addition to sales to our own customers, we also sell power to otherutilities as available, including through the Southwest Power Pool (SPP) energyimbalance services (EIS) market. See “Competition” below. The majority of ouroff-system sales margins are now included as a component of the fuel adjustmentclause in our Missouri, Kansas and Oklahoma jurisdictions and generally adjustthe fuel and purchased power expense. As a result, the off-system sales marginflows back to the customer. The following table sets forth informationregarding these sales and related expenses for the quarters ended June 30:

 
| **(in millions)**         | ** ** | **2009**   | ** ** | **2008**   | ** ** |
|---------------------------|------------|------------|------------|------------|------------|
| ** **                | ** ** | ** ** | ** ** | ** ** | ** ** |
| EIS revenues              |       | $          | 0.9        |       | $          | 4.4 |   |
| Other revenues            |       | 1.7        |       | 3.0        |       |
| Total off-system revenues |       | 2.6        |       | 7.4        |       |
|                      |       |       |       |       |       |
| EIS expenses              |       | 0.8        |       | 2.7        |       |
| Other expenses            |       | 1.6        |       | 2.5        |       |
| Total off-system expenses |       | 2.4        |       | 5.2        |       |
|                      |       |       |       |       |       |
| Net                       |       | $          | 0.2        |       | $          | 2.2 |   |

 

----

**Differences could occur due to rounding.*

 

Revenues and related expenses were less during the second quarter of2009 as compared to the second quarter of 2008 primarily due to decreasedmarket demand and lower gas prices that made it more economical for utilitiesto generate their own power rather than purchase it. Total purchased powerrelated expenses are included in our discussion of purchased power costs below.

 

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**Miscellaneous Revenues**

 

Our miscellaneous revenues were $1.4 million for the second quarter of2009 as compared to $1.5 million in the second quarter of 2008. These revenuesare comprised mainly of transmission revenues, late payment fees and renewableenergy credit sales.

 

**Operating Revenue Deductions**

 

During the second quarter of 2009, total electric segment operatingexpenses decreased approximately $1.6 million (1.8%) compared with the sameperiod last year.

 

Totalfuel and purchased power expenses decreased approximately $5.4 million (11.5%)during the second quarter of 2009. 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 ofoperations for the second quarter of 2009 and 2008.

 
| **(in millions)**                                            | ** ** | **2009** | ** ** | **2008** | ** ** |
|--------------------------------------------------------------|------------|----------|------------|----------|------------|
| Actual fuel and purchased power expenditures                 |       | $        | 38.7       |     | $          | 46.9 |   |
| Kansas regulatory adjustments*                               |       | 0.1      |       | —   |       |
| Missouri fuel adjustment deferral*                           |       | 2.6      |       | —   |       |
| Missouri fuel adjustment recovery**                          |       | 0.1      |       | —   |       |
| Unrealized loss on derivatives                               |       | —   |       | —   |       |
| Total fuel and purchased power expense per income  statement |       | $        | 41.5       |     | $          | 46.9 |   |

 

----

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

**Currently beingrecovered from customers from prior deferral period.

 

Theoverall fuel and purchased power decrease reflects decreased generation by bothour coal-fired and gas-fired units during the second quarter of 2009. Thedecrease in fuel costs includes theeffect of decreased market demand resultingfrom milder weather in April and May of 2009 as well as decreasedoff-system sales of $2.8 million**.**

 

Summarizedin the table below are our estimated cost and volume changes in the componentsof fuel and purchased power expenses for the second quarter of 2009 as comparedto the second quarter of 2008. This table incorporates all the changesmentioned above. As shown below, the largest impact on fuel and purchased powercosts was decreased generation by our gas-fired units and lower gas priceswhich decreased both generation and purchased power costs.

 
| **(in millions)**                    | ** ** | **2009** | ** ** |
|--------------------------------------|------------|----------|------------|
| Purchased power (cost per mWh)       |       | $        | (4.9       | ) |
| Purchased power spot purchase volume |       | 1.4      |       |
| Coal (cost per mWh)                  |       | 1.2      |       |
| Coal generation volume               |       | (1.4     | )          |
| Natural gas (cost per mWh)           |       | (2.6     | )          |
| Natural gas generation volume        |       | (2.2     | )          |
| Other (including fuel adjustments)   |       | 3.1      |       |
| TOTAL                                |       | $        | (5.4       | ) |

 

Regulatedoperating expenses increased approximately $0.5 million (3.1%) during thesecond quarter of 2009 as compared to the same period in 2008 primarily due toincreases of $0.4 million in customer accounts expenses (including $0.2 millionin uncollectible accounts), $0.3 million in other steam power expense, $0.3million in general labor costs, $0.2 million in professional services, $0.1million in transmission expense and $0.1 million in other power operationexpense. These increases were partially offset by decreases of $0.6 million inemployee health care expense and $0.3 million in employee pension expense.

 

Maintenance and repairs expense increased approximately $2.1 million(31.7%) in the second quarter of 2009 as compared to 2008 primarily due toincreases of $1.2 million in distribution maintenance costs (including $0.9million of ice storm related amortization), $0.6 million in

 

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maintenance and repairs expense at the Asbury plant and $0.3 million inmaintenance and repairs expense at the State Line Combined Cycle (SLCC) plant.

 

Depreciation and amortization expense decreased approximately $1.2 million(8.9%) during the quarter primarily due to reduced regulatory amortizationresulting from the 2008 Missouri rate case that went into effect on August 23,2008. Other taxes increased approximately $0.3 million during the secondquarter of 2009 due to increased property tax reflecting our additions to plantin service and increased municipal franchise taxes.

 

***Six Months Ended June 30, 2009 Compared to SixMonths Ended June 30, 2008***

 

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

 

KWh sales for our on-system customers decreased during the six monthsended June 30, 2009 as compared to the six months ended June 30, 2008primarily due to milder weather in the first 5 months of 2009 as compared tothe same period in 2008. However, revenues for our on-system customersincreased approximately $8.5 million, or 4.5%. Rate changes contributed anestimated $13.3 million during the six months ended June 30, 2009 whilesales growth contributed an estimated $0.5 million. Weather and other relatedfactors decreased revenues by an estimated $5.3 million compared to the sixmonths ended June 30, 2008.

 

The decrease in residential kWh sales during the six months ended June 30,2009 was primarily due to the mild weather in 2009. The related revenuesincreased during the second quarter of 2009, primarily as a result of the 2008Missouri rate increase.

 

Commercial kWh sales and revenues increased during the six months endedJune 30, 2009 due to sales growth while the increase in revenues was alsodue to the 2008 Missouri rate increase.

 

Industrial kWh sales decreased 7.4% mainly due to a slowdown created byeconomic uncertainty while the associated revenues increased 0.8% due to theeffects of the Missouri rate increase which offset the economic conditions**.**

 

On-system wholesale kWh sales decreased during the six months ended June 30,2009 reflecting the economic conditions and mild weather discussed above whilethe revenues associated with these FERC-regulated sales decreased more as aresult of the fuel adjustment clause applicable to such sales.

 

**Off-System Electric Transactions**

 

Inaddition to sales to our own customers, we also sell power to other utilitiesas available, including through the SPP EIS market. See “Competition” below.The majority of our off-system sales margins are now included as a component ofthe fuel adjustment clause in our Missouri, Kansas and Oklahoma jurisdictionsand generally adjust the fuel and purchased power expense. The following tablesets forth information regarding these sales and related expenses for the sixmonths ended June 30:

 
| **(in millions)**         | ** ** | **2009**   | ** ** | **2008**   | ** ** |
|---------------------------|------------|------------|------------|------------|------------|
| ** **                | ** ** | ** ** | ** ** | ** ** | ** ** |
| EIS revenues              |       | $          | 2.4        |       | $          | 7.4 |   |
| Other revenues            |       | 4.2        |       | 7.4        |       |
| Total off-system revenues |       | 6.6        |       | 14.8       |       |
|                      |       |       |       |       |       |
| EIS expenses              |       | 2.0        |       | 5.0        |       |
| Other expenses            |       | 3.6        |       | 5.9        |       |
| Total off-system expenses |       | 5.6        |       | 10.9       |       |
|                      |       |       |       |       |       |
| Net                       |       | $          | 1.0        |       | $          | 3.9 |   |

 

----

**Differences could occur due to rounding.*

 

Revenues and related expenses were less during the six months ended June 30,2009 as compared to the same period in 2008 primarily due to decreased marketdemand resulting from

 

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mild weather and decreased gas prices. Total purchased power relatedexpenses are included in our discussion of purchased power costs below.

 

**Miscellaneous Revenues**

 

Our miscellaneous revenues were $3.2 million for the six months ended June 30,2009 as compared to $3.3 million during the same period in 2008. These revenuesare comprised mainly of transmission revenues, late payment fees and renewableenergy credit sales.

 

**Operating Revenue Deductions**

 

During the six months ended June 30, 2009, total electric segmentoperating expenses decreased approximately $8.4 million (4.5%) compared withthe same period last year.

 

Totalfuel and purchased power expenses decreased approximately $15.5 million (15.0%)during the six months ended June 30, 2009. The table below is areconciliation of our actual fuel and purchased power expenditures (netted withthe regulatory adjustments) to the fuel and purchased power expense shown onour statement of operations for the six months ended June 30, 2009 and2008.

 
| **(in millions)**                                            | ** ** | **2009** | ** ** | **2008** | ** ** |
|--------------------------------------------------------------|------------|----------|------------|----------|------------|
| Actual fuel and purchased power expenditures                 |       | $        | 88.4       |     | $          | 104.4 |   |
| Kansas regulatory adjustments*                               |       | 0.4      |       | (0.5     | )          |
| Missouri fuel adjustment deferral*                           |       | (0.5     | )          | —   |       |
| Missouri fuel adjustment recovery**                          |       | 0.1      |       | —   |       |
| Unrealized loss on derivatives                               |       | —   |       | —   |       |
| Total fuel and purchased power expense per income  statement |       | $        | 88.4       |     | $          | 103.9 |   |

 

----

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

**Currently beingrecovered from customers from prior deferral period.

 

Theoverall fuel and purchased power expenses decrease reflects decreasedgeneration by both our coal-fired and gas-fired units during the six monthsended June 30, 2009 as compared to the same period in 2008. The decreasein fuel costs includes theeffect of decreased market demand resulting from milder weather in 2009as well as decreased off-system sales of $5.3 million.

 

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 30,2009 as compared to the six months ended June 30, 2008. This tableincorporates all the changes mentioned above. As shown below, the largestimpact on fuel and purchased power costs was decreased generation by ourgas-fired units and lower gas prices which decreased both generation andpurchased power costs.

 
| **(in millions)**                              | ** ** | **2009** | ** ** |
|------------------------------------------------|------------|----------|------------|
| Purchased power (cost per mWh)                 |       | $        | (8.5       | ) |
| Purchased power spot purchase volume           |       | 1.4      |       |
| Coal (cost per mWh)                            |       | 2.7      |       |
| Coal generation volume                         |       | (1.4     | )          |
| Natural gas (cost per mWh)                     |       | (4.7     | )          |
| Natural gas generation volume                  |       | (8.2     | )          |
| Natural gas – gain on unwind of positions |       | 2.1      |       |
| Other (including fuel adjustments)             |       | 1.1      |       |
| TOTAL                                          |       | $        | (15.5      | ) |

 

Regulatedoperating expenses for our electric segment decreased approximately $0.3million (0.9%) during the six months ended June 30, 2009 as compared tothe same period in 2008 primarily due to decreases of****$1.2million in employee health care expense, $0.5 million in employee pensionexpense, $0.2 million in injuries and damages expense and $0.2 million indistribution expense. These decreases were partially offset by increases of$0.7 million in other

 

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steampower expense, $0.5 million in professional services, $0.4 million in customeraccounts expenses (including $0.2 million in uncollectible accounts) and $0.2million in transmission expense.

 

Maintenance and repairs expense increased approximately $4.3 million(35.9%) during the six months ended June 30, 2009 as compared to 2008primarily due to increases of $2.7 million in distribution maintenance costs(including $1.9 million of ice storm related amortization), $0.8 million inmaintenance and repairs expense due to the SLCC maintenance outage in the firstquarter of 2009, $0.6 million in maintenance and repairs expense at the Asburyplant, $0.1 million in maintenance and repairs expense at the Iatan plant and$0.1 million in transmission maintenance expense.

 

Depreciation and amortization expense decreased approximately $2.2million (8.3%) during the six months ended June 30, 2009 primarily due toreduced regulatory amortization resulting from the 2008 Missouri rate case thatwent into effect on August 23, 2008. Other taxes increased approximately$0.5 million during the six months ended June 30, 2009 due to increasedproperty tax reflecting our additions to plant in service and increasedmunicipal franchise taxes.

 

***Twelve Months Ended June 30, 2009 Compared toTwelve Months Ended June 30, 2008***

 

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

 

For the twelve months ended June 30, 2009, kWh sales to our on-systemcustomers decreased 2.6% with the associated revenues increasing approximately$12.1 million (3.0%). Rate changes, primarily the August 2008 Missourirate increase (discussed below), contributed an estimated $21.5 million torevenues while continued sales growth contributed an estimated $2.3 million.Weather and other related factors decreased revenues an estimated $11.7million.

 

The decrease in residential kWh sales during the twelve months ended June 30,2009 was primarily due to the mild weather in 2009 and the third quarter of2008. The related revenues increased during the twelve months ended June 30,2009 primarily as a result of the 2008 Missouri rate increase. Commercial kWhsales increased primarily due to sales growth while the increase in associatedrevenues was also due to the 2008 Missouri rate increase. Industrial kWh salesdecreased mainly due to a slowdown created by economic uncertainty while theassociated revenues increased due to the effects of the Missouri rate increasewhich offset the economic conditions**.**On-system wholesale kWh sales and revenues decreasedreflecting the general economic conditions and mild weather.

 

**Off-System Electric Transactions**

 

Inaddition to sales to our own customers, we also sell power to other utilitiesas available, including through the SPP EIS market. See “Competition” below.The majority of our off-system sales margins are now included as a component ofthe fuel adjustment clause in our Missouri, Kansas and Oklahoma jurisdictionsand generally adjust the fuel and purchased power expense. The following tablesets forth information regarding these sales and related expenses for thetwelve months ended June 30:

 
| **(in millions)**         | ** ** | **2009**   | ** ** | **2008**   | ** ** |
|---------------------------|------------|------------|------------|------------|------------|
| ** **                | ** ** | ** ** | ** ** | ** ** | ** ** |
| EIS revenues              |       | $          | 8.1        |       | $          | 12.9 |   |
| Other revenues            |       | 13.4       |       | 14.2       |       |
| Total off-system revenues |       | 21.5       |       | 27.1       |       |
|                      |       |       |       |       |       |
| EIS expenses              |       | 6.4        |       | 9.0        |       |
| Other expenses            |       | 9.8        |       | 10.8       |       |
| Total off-system expenses |       | 16.2       |       | 19.8       |       |
|                      |       |       |       |       |       |
| Net                       |       | $          | 5.3        |       | $          | 7.3 |   |

 

----

**Differences could occur due to rounding.*

 

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Revenues and related expenses were less during the twelve months ended June 30,2009 as compared to the same period in 2008 primarily due to decreased marketdemand. Total purchased power related expenses are included in our discussionof purchased power costs below.

 

**Miscellaneous Revenues**

 

Our miscellaneous revenues were $6.9 million for the twelve monthsended June 30, 2009 as compared to $6.2 million during the same period in2008. These revenues are comprised mainly of transmission revenues, latepayment fees and renewable energy credit sales.

 

**Operating Revenue Deductions**

 

During the twelve months ended June 30, 2009, total electricsegment operating expenses decreased approximately $6.0 million (1.6%) comparedwith the same period last year.

 

Totalfuel and purchased power expenses decreased approximately $19.3 million (9.3%)during the twelve months ended June 30, 2009. The table below is a reconciliationof our actual fuel and purchased power expenditures (netted with the regulatoryadjustments) to the fuel and purchased power expense shown on our statement ofoperations for the twelve months ended June 30, 2009 and 2008.

 
| **(in millions)**                                            | ** ** | **2009** | ** ** | **2008** | ** ** |
|--------------------------------------------------------------|------------|----------|------------|----------|------------|
| Actual fuel and purchased power expenditures                 |       | $        | 188.1      |     | $          | 208.3 |   |
| Kansas regulatory adjustments*                               |       | 0.3      |       | (0.5     | )          |
| Missouri fuel adjustment deferral*                           |       | (0.3     | )          | —   |       |
| Missouri fuel adjustment recovery**                          |       | 0.1      |       | —   |       |
| Unrealized loss on derivatives                               |       | 0.3      |       | —   |       |
| Total fuel and purchased power expense per income  statement |       | $        | 188.5      |     | $          | 207.8 |   |

 

----

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

**Currently beingrecovered from customers from prior deferral period.

 

Theoverall fuel and purchased power expenses decrease includes theeffect of decreased marketdemand resulting from mild weather in 2009 and the third quarter of 2008, aswell as****the effects of an extended outage atthe Asbury plant lasting from the fourth quarter of 2007 into the first quarterof 2008 during which time we relied on purchased power and our gas-fired unitsto replace our coal-fired generation. The decrease in fuel costs includes theeffect of decreasedoff-system sales of $3.6 million.

 

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 30,2009 as when compared to the twelve months ended June 30, 2008. This tableincorporates all the changes mentioned above. As shown below, the largestimpact on fuel and purchased power costs was decreased generation by ourgas-fired units and lower gas prices which decreased both generation andpurchased power costs.

 
| **(in millions)**                              | ** ** | **2009** | ** ** |
|------------------------------------------------|------------|----------|------------|
| Purchased power (cost per mWh)                 |       | $        | (5.5       | ) |
| Purchased power spot purchase volume           |       | (0.8     | )          |
| Coal (cost per mWh)                            |       | 5.7      |       |
| Coal generation volume                         |       | 1.8      |       |
| Natural gas (cost per mWh)                     |       | (11.8    | )          |
| Natural gas generation volume                  |       | (13.0    | )          |
| Natural gas – gain on unwind of positions |       | 2.1      |       |
| Other (including fuel adjustments)             |       | 2.2      |       |
| TOTAL                                          |       | $        | (19.3      | ) |

 

Regulatedoperating expenses for our electric segment increased approximately $0.2million (0.3%) during the twelve months ended June 30, 2009 as compared tothe same period in 2008 primarily due to increases of****$1.2million in other steam power expense, $0.5 million in injuries and

 

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damagesexpense, $0.4 million in transmission expense, $0.3 million in professionalservices, $0.3 million in other power supply expense, $0.2 million in directorand stockholder expense, and $0.2 million in property insurance expense. Theseincreases were partially offset by decreases of $1.7 million in employee healthcare expense, $0.9 million in employee pension expense, $0.2 million in generallabor costs and $0.1 million in uncollectible accounts.

 

Maintenance and repairs expense increased approximately $5.6 million(21.3%) during the twelve months ended June 30, 2009 as compared to 2008primarily due to increases of $3.1 million in distribution maintenance costs(including $3.3 million of ice storm related amortization), $0.9 million inmaintenance and repairs expense due to the SLCC maintenance outage in the firstquarter of 2009, $0.9 million in maintenance and repairs expense at the Iatanplant due to an outage in the fourth quarter of 2008, $0.4 million in maintenanceand repairs expense at the Riverton plant mainly due to the extended outage onUnit 8 to repair damage to high pressure blades discovered during Riverton’sscheduled maintenance outage in May 2008, $0.4 million in maintenance andrepairs expense at the Asbury plant, and $0.3 million in transmission expense.These increases were partially offset by a $0.4 million decrease in maintenanceand repairs expense at the Energy Center plant.

 

Depreciation and amortization expense decreased approximately $3.0million (5.9%) during the twelve months ended June 30, 2009 primarily dueto reduced regulatory amortization resulting from the 2008 Missouri rate casethat went into effect on August 23, 2008. Other taxes increasedapproximately $0.4 million during the twelve months ended June 30, 2009due to increased property tax reflecting our additions to plant in service andincreased municipal franchise taxes.

 

***Gas Segment***

 

**Gas Operating Revenues and Sales**

 

**Total Gas Delivered toCustomers**

 
| ** **                 | ** ** | **Three Months Ended** | ** ** | **Six months ended** | ** ** | **Twelve months ended** | ** ** |
|----------------------------|------------|------------------------|------------|----------------------|------------|-------------------------|------------|
| ** **                 | ** ** | ** **             | ** ** | ** **           | ** ** | **%**                   | ** ** | ** ** | ** ** | ** ** | ** ** | **%** | ** ** | ** ** | ** ** | ** ** | ** ** | **%** | ** ** |
| **bcf sales**              | ** ** | **2009**               | ** ** | **2008**             | ** ** | **change**              | ** ** | **2009** | ** ** | **2008** | ** ** | **change** | ** ** | **2009** | ** ** | **2008** | ** ** | **change** | ** ** |
| Residential                |       | 0.29                   |       | 0.32                 |       | (10.0                   | )%         | 1.60 |   | 1.85 |   | (13.5 | )% | 2.70 |   | 2.97 |   | (9.0 | )% |
| Commercial                 |       | 0.15                   |       | 0.17                 |       | (8.3                    | )          | 0.72 |   | 0.84 |   | (14.0 | ) | 1.28 |   | 1.38 |   | (7.3 | ) |
| Industrial*                |       | 0.02                   |       | 0.15                 |       | (89.5                   | )          | 0.17 |   | 0.20 |   | (16.0 | ) | 0.52 |   | 0.25 |   | 108.5 |   |
| Other**                    |       | 0.00                   |       | 0.00                 |       | (25.9                   | )          | 0.02 |   | 0.03 |   | (18.0 | ) | 0.03 |   | 0.03 |   | (6.5 | ) |
| Total  retail sales        |       | 0.46                   |       | 0.64                 |       | (28.3                   | )          | 2.51 |   | 2.92 |   | (13.9 | ) | 4.53 |   | 4.63 |   | (2.1 | ) |
| Transportation  sales      |       | 0.92                   |       | 0.85                 |       | 9.5                     |       | 2.08 |   | 2.20 |   | (5.5 | ) | 3.94 |   | 4.23 |   | (6.9 | ) |
| Total  gas operating sales |       | 1.38                   |       | 1.49                 |       | (6.9                    | )          | 4.59 |   | 5.12 |   | (10.3 | ) | 8.47 |   | 8.86 |   | (4.4 | ) |

 

----

**Percentagechange reflects the transfer of a customer from transportation to industrialsales in April 2008 and back to transportation in May 2009.*

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

 

**Operating Revenues andCost of Gas Sold**

 
| ** **                                        | ** ** | **Three Months Ended** | ** ** | **Six months ended** | ** ** | **Twelve months ended** | ** ** |
|---------------------------------------------------|------------|------------------------|------------|----------------------|------------|-------------------------|------------|
| **($ in millions)**                          | ** ** | **2009**               | ** ** | **2008**             | ** ** | **% change**            | ** ** | **2009** | ** ** | **2008** | ** ** | **% change** | ** ** | **2009** | ** ** | **2008** | ** ** | **% change** | ** ** |
| Residential                                       |       | $                      | 4.9        |                 | $          | 5.0                     |       | (2.6 | )% | $ | 23.0 |   | $ | 23.1 |   | (0.6 | )% | $ | 39.5 |   | $ | 38.3 |   | 3.1 | % |
| Commercial                                        |       | 2.1                    |       | 2.2                  |       | (3.0                    | )          | 9.5 |   | 9.6 |   | (1.2 | ) | 17.3 |   | 16.3 |   | 5.9 |   |
| Industrial*                                       |       | 0.2                    |       | 1.4                  |       | (85.0                   | )          | 1.6 |   | 1.8 |   | (9.9 | ) | 4.9 |   | 2.3 |   | 118.2 |   |
| Other**                                           |       | 0.0                    |       | 0.0                  |       | (19.9                   | )          | 0.3 |   | 0.3 |   | (5.7 | ) | 0.4 |   | 0.4 |   | 7.3 |   |
| Total  retail revenues                            |       | $                      | 7.2        |                 | $          | 8.6                     |       | (15.9 | ) | $ | 34.4 |   | $ | 34.8 |   | (1.3 | ) | $ | 62.1 |   | $ | 57.3 |   | 8.4 |   |
| Other  revenues                                   |       | 0.0                    |       | 0.0                  |       | (15.8                   | )          | 0.1 |   | 0.1 |   | 0.1 |   | 0.2 |   | 0.2 |   | 0.4 |   |
| Transportation  revenues*                         |       | 0.7                    |       | 0.5                  |       | 28.4                    |       | 1.5 |   | 1.5 |   | 1.7 |   | 2.7 |   | 2.8 |   | (3.0 | ) |
| Total  gas operating revenues                     |       | $                      | 7.9        |                 | $          | 9.1                     |       | (13.4 | ) | $ | 36.0 |   | $ | 36.4 |   | (1.1 | ) | $ | 65.0 |   | $ | 60.3 |   | 7.9 |   |
| Cost  of gas sold                                 |       | 4.2                    |       | 5.3                  |       | (20.5                   | )          | 23.5 |   | 23.0 |   | 2.3 |   | 43.1 |   | 37.2 |   | 16.1 |   |
| Gas  operating revenues over cost of gas in rates |       | $                      | 3.7        |                 | $          | 3.8                     |       | (3.7 | ) | $ | 12.5 |   | $ | 13.4 |   | (7.0 | ) | $ | 21.9 |   | $ | 23.1 |   | (5.3 | ) |

 

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**Percentagechange reflects the transfer of a customer from transportation to industrialsales in April 2008 and back to transportation in May 2009.*

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

 

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***Quarter Ended June 30, 2009 Compared toQuarter Ended June 30, 2008***

 

**Operating Revenues and bcf Sales**

 

Gas retail sales decreased28.3% during the second quarter of 2009 as compared to 2008 primarily due tomild weather, customer contraction of 1.07% and the suspension of operations bya large volume industrial customer. Gas sales are less during the summer monthsas the heating season runs from November to March of each year.Residential sales decreased 10.0% and commercial sales decreased 8.3% duringthe second quarter of 2009 as compared to the second quarter of 2008 primarilydue to the mild weather and customer contraction. Heating degree days were 8.6%lower in the second quarter of 2009 as compared to the second quarter of 2008.Industrial sales decreased during the second quarter of 2009 as compared to thesame period in 2008 due to the suspension of operations by a large volumeindustrial customer in the first quarter of 2009.

 

During the second quarter of2009, gas segment revenues were approximately $7.9 million as compared to $9.1million in the second quarter of 2008, a decrease of 13.4%. During the secondquarter of 2009, our PGA revenue (whichrepresents the cost of gas recovered from our customers) wasapproximately $4.2 million as compared to $5.3 million in the second quarter of2008, a decrease of approximately $1.1 million. This decrease was largelydriven by the decrease in industrial sales and a decrease in the PGA that wentinto effect May 15, 2009.

 

Our PGA clause allows us torecover from our customers, subject to routine regulatory review, the cost ofpurchased gas supplies, transportation and storage, including costs associatedwith the use of financial instruments to hedge the purchase price of naturalgas. Pursuant to the provisions of the PGA clause, the difference betweenactual costs incurred and costs recovered through the application of the PGAare reflected as a regulatory asset or regulatory liability until the balanceis recovered from or credited to customers. As of June 30, 2009, we hadunrecovered purchased gas costs of $0.3 million recorded as a regulatory asset.

 

**OperatingRevenue Deductions**

 

Totalother operating expenses were approximately $2.6 million during both the secondquarter of 2009 and 2008 although uncollectible accounts decreased $0.2 millionin the second quarter of 2009 as compared to the same period in 2008. Our gassegment had a net loss of $0.8 million for the second quarter of 2009 ascompared to a net loss of $0.6 million for the second quarter of 2008, which isnot unexpected due to the seasonality of the gas segment whose heating seasonruns from November to March of each year.

 

***Six Months Ended June 30, 2009 Compared to SixMonths Ended June 30, 2008***

 

**Operating Revenues and bcf Sales**

 

Gas retail sales decreased13.9% during the six months ended June 30, 2009 as compared to the sameperiod in 2008 mainly due to mild weather in the first and second quarters of2009, customer contraction and the suspension of operations by a large volumeindustrial customer in the first quarter of 2009. Residential and commercialsales decreased during the six months ended June 30, 2009 as compared tothe same period in 2008 primarily due to the milder weather and customercontraction. Industrial sales decreased during the six months ended June 30,2009 as compared to the same period in 2008 mainly due to the suspension ofoperations by a large volume industrial customer in the first quarter of 2009.

 

During the six months ended June 30,2009, gas segment revenues were approximately $36.0 million as compared to$36.4 million in the six months ended June 30, 2008, a decrease of 1.1%.This decrease was largely driven by the decrease in industrial sales, whichoffset a slight increase in PGA revenues. During the six months ended June 30,2009, our PGA revenue was approximately $23.5 million as compared to $23.0million during the six months ended June 30, 2008, an increase ofapproximately $0.5 million.

 

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**OperatingRevenue Deductions**

 

Totalother operating expenses were $5.4 million for the six months ended June 30,2009 as compared to $5.1 million for the six months ended June 30, 2008.This increase was mainly due to an increase of $0.2 million in uncollectible accountsand an increase of****$0.1 millionin employee health care expense and employee pension expense. Our gas segmenthad net income of $1.0 million for the six months ended June 30, 2009 ascompared to $1.8 million for the six months ended June 30, 2008.

 

***Twelve Months Ended June 30, 2009 Compared toTwelve Months Ended June 30, 2008***

 

**Operating Revenues and bcf Sales**

 

Gas retail sales decreased2.1% during the twelve months ended June 30, 2009 mainly due to a decreasein residential and commercial sales as compared to 2008. Industrial salesincreased during the twelve months ended June 30, 2009 as compared to thesame period in 2008 due to the transfer of a large volume industrial customerfrom transportation to sales service and the addition of a new large volumeindustrial customer in the second quarter of 2008.

 

During the twelve monthsended June 30, 2009, gas segment revenues were approximately $65.0 millionas compared to $60.3 million in the twelve months ended June 30, 2008, anincrease of 7.9%. This increase was largely driven by the increase inindustrial sales and PGA revenue. During the twelve months ended June 30,2009, our PGA revenue was approximately $43.1 million as compared to $37.2million during the twelve months ended June 30, 2008, an increase ofapproximately $5.9 million.

 

**OperatingRevenue Deductions**

 

Totalother operating expenses were $10.4 million for the twelve months ended June 30,2009 as compared to $9.9 million for the twelve months ended June 30,2008. This increase was mainly due to a $0.3 million increase in customeraccounts expense and a $0.2 million increase in distribution operation expense.Our gas segment had net income of $0.9 million for the twelve months ended June 30,2009 as compared to $1.8 million for the twelve months ended June 30,2008.

 

***Other Segment***

 

Our other segment consists of ournon-regulated business, primarily the leasing of fiber optics cable andequipment (which we are also using in our own utility operations). Thefollowing table represents the results for our other segment for the applicableperiods ended June 30 (in millions):

 
| ** **         | ** ** | **Three Months Ended** | ** ** | **Six Months Ended** | ** ** | **Twelve Months Ended** | ** ** |
|--------------------|------------|------------------------|------------|----------------------|------------|-------------------------|------------|
| **(in  millions)** | ** ** | **2009**               | ** ** | **2008**             | ** ** | **2009**                | ** ** | **2008** | ** ** | **2009** | ** ** | **2008** | ** ** |
| Revenues           |       | $                      | 1.4        |                 | $          | 1.3                     |       | $ | 2.7 |   | $ | 2.4 |   | $ | 5.3 |   | $ | 4.3 |   |
| Expenses           |       | 1.0                    |       | 1.0                  |       | 2.0                     |       | 1.9 |   | 4.5 |   | 3.5 |   |
| Net  income*       |       | $                      | 0.4        |                 | $          | 0.3                     |       | $ | 0.7 |   | $ | 0.5 |   | $ | 0.8 |   | $ | 0.9 |   |

 

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**Differencescould occur due to rounding.*

 

***Consolidated Company***

 

**Income Taxes**

 

Ourconsolidated provision for income taxes increased approximately $2.1 million duringthe second quarter of 2009 as compared to the same period in 2008 mainly due toincreased income. Our consolidated effective federal and state income tax ratefor the second quarter of 2009 was 34.7% as compared to 31.9% for the secondquarter of 2008.

 

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Ourconsolidated provision for income taxes increased approximately $4.5 millionduring the six months ended June 30, 2009 as compared to the same periodin 2008. This resulted primarily from increased income. Our consolidatedeffective federal and state income tax rate for the six months ended June 30,2009 was 34.2% as compared to 31.2% for the same period in 2008.

 

Ourconsolidated provision for income taxes increased approximately $8.5 millionduring the twelve months ended June 30, 2009 as compared to the twelvemonths ended June 30, 2008, primarily resulting from higher income. Oureffective federal and state income tax rate for the twelve months ended June 30,2009 was 33.5% as compared to 30.8% for the same period in 2008.

 

Therate in all periods is higher primarily due to lower tax benefits received fromcost of plant retirement expenditures. Our cost of retirement expenditures wasunusually high during the twelve months ended June 30, 2008 due to the icestorms we experienced. This reduced benefit during this period was partiallyoffset by an increase in the tax effects of equity AFUDC.

 

**Nonoperating Items**

 

Total allowance for funds used duringconstruction (AFUDC) increased $0.3 million in the second quarter of 2009 ascompared to 2008. AFUDC increased $1.5 million during the six months ended June 30,2009 and increased $4.5 million during the twelve months ended June 30,2009 as compared to the same periods in the prior year due to higher levels ofconstruction in each period.

 

Totalinterest charges on long-term and short-term debt for the periods ended June 30,2009 are shown below. The increases in long-term debt interest for all threeperiods reflect the interest on the $90 million principal amount of firstmortgage bonds we issued May 16, 2008, and the $75 million principalamount of first mortgage bonds we issued March 27, 2009. The decreases inshort-term debt interest for all three periods reflect lower cost of borrowing.

 
| ** **                                    | ** ** | **Interest Charges** | ** ** |
|-----------------------------------------------|------------|----------------------|------------|
| ** **                                    | ** ** | **(in millions)**    | ** ** |
| ** **                                    | ** ** | **Second**           | ** ** | **Second** | ** ** | ** ** | ** ** | **6 Months** | ** ** | **6 Months** | ** ** | ** ** | ** ** | **12 Months** | ** ** | **12 Months** | ** ** | ** ** | ** ** |
| ** **                                    | ** ** | **Quarter**          | ** ** | **Quarter** | ** ** | **%** | ** ** | **Ended** | ** ** | **Ended** | ** ** | **%** | ** ** | **Ended** | ** ** | **Ended** | ** ** | **%** | ** ** |
| ** **                                    | ** ** | **2009**             | ** ** | **2008** | ** ** | **Change*** | ** ** | **2009** | ** ** | **2008** | ** ** | **Change*** | ** ** | **2009** | ** ** | **2008** | ** ** | **Change*** | ** ** |
| Long-term debt interest                       |       | 10.9                 |       | 8.8 |   | 23.5 | % | 20.5 |   | 16.9 |   | 21.5 | % | 39.7 |   | 33.0 |   | 20.1 | % |
| Short-term debt interest                      |       | 0.2                  |       | 0.3 |   | (33.8 | ) | 0.8 |   | 0.8 |   | (6.8 | ) | 1.8 |   | 2.4 |   | (26.4 | ) |
| Note payable to securitization trust interest |       | 1.1                  |       | 1.1 |   | 0.0 |   | 2.1 |   | 2.1 |   | 0.0 |   | 4.2 |   | 4.2 |   | 0.0 |   |
| Iatan carrying charges                        |       | (0.6                 | )          | — |   | — |   | (0.6 | ) | — |   | — |   | (0.6 | ) | — |   | — |   |
| Other interest                                |       | 0.1                  |       | 0.3 |   | (50.9 | ) | 0.3 |   | 0.6 |   | (44.3 | ) | 0.9 |   | 1.1 |   | (14.8 | ) |
| Total interest charges                        |       | 11.7                 |       | 10.5 |   | 11.2 |   | 23.1 |   | 20.4 |   | 13.3 |   | 46.0 |   | 40.7 |   | 12.8 |   |

 

Wehad no gains or losses from discontinued operations in the twelve months ended June 30,2009 compared to a gain of $0.1 million for the twelve months ended June 30,2008.

 

**OtherComprehensive Income**

 

Thechange in the fair value of the effective portion of our open gas contractsdesignated as cash flow hedges entered into prior to September 1, 2008 forour electric segment and the gains and losses on these contracts settled duringthe periods being reported, including the tax effect of these items, arereflected in our Consolidated Statement of Comprehensive Income. The fair valueof open electric segment derivative contracts purchased prior to September 1,2008, the effective date of our fuel adjustment mechanism, increased $1.9million in the second quarter of 2009, reflecting falling natural gas prices.This net change is recorded as accumulated other comprehensive income in thecapitalization section of our balance sheet and does not affect net income orearnings per share. All of these contracts have been designated as cash flowhedges. The unrealized gains and losses accumulated in other comprehensiveincome are reclassified to fuel and purchased power in the periods in which thehedged transaction is actually realized or no longer qualifies for hedgeaccounting.

 

The following table sets forth the pre-taxgains/(losses) of this activity and the related tax effect in OtherComprehensive Income for the presented periods ended June 30:

 

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| ** **                                       | ** ** | **Three Months Ended** | ** ** | **Six Months Ended** | ** ** | **Twelve Months Ended** | ** ** |
|--------------------------------------------------|------------|------------------------|------------|----------------------|------------|-------------------------|------------|
| **(in millions)**                                | ** ** | **2009**               | ** ** | **2008**             | ** ** | **2009**                | ** ** | **2008** | ** ** | **2009** | ** ** | **2008** | ** ** |
| Natural  gas contracts settled **(1)**           |       | $                      | 1.7        |                 | $          | (1.7                    | )          | $ | 6.7 |   | $ | (2.6 | ) | $ | 5.4 |   | $ | (4.1 | ) |
| Change  in FMV of open contracts for natural gas |       | $                      | 1.9        |                 | $          | 22.8                    |       | $ | (7.5 | ) | $ | 33.8 |   | $ | (58.7 | ) | $ | 30.4 |   |
| Taxes                                            |       | $                      | (1.4       | )                    | $          | (8.0                    | )          | $ | 0.3 |   | $ | (11.9 | ) | $ | 20.3 |   | $ | (10.0 | ) |
| Total  change in OCI – net of tax           |       | $                      | 2.2        |                 | $          | 13.1                    |       | $ | (0.5 | ) | $ | 19.3 |   | $ | (33.0 | ) | $ | 16.3 |   |

 

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*(1) Reflected in fuel expense.*

 

**RATE MATTERS**

 

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

 

***Electric Segment***

 

The following table sets forth information regardingelectric and water rate increases since January 1, 2007:

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

 

*Missouri*

 

*2007 Rate Case*

 

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

 

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

 

The MPSC also authorized a fuel adjustmentclause for our Missouri customers effective September 1, 2008. The MPSCestablished a base cost for the recovery of fuel and purchased power expensesused to supply energy. The clause permits the distribution to customers of 95%of the changes in fuel and purchased power costs above or below the base cost.Off-system sales margins are also part of the recovery of fuel and purchasedpower costs. As a result, the off-system sales margin flows back to thecustomer. Rates related to the recovery of fuel and purchased power costs willbe modified twice a year subject to the review and approval by the MPSC. Inaccordance with FAS 71, 95% of the difference between the actual cost of fueland purchased power and the base cost of fuel and purchased power recoveredfrom our customers is recorded as an adjustment to fuel and purchased powerexpense with a corresponding regulatory asset or a regulatory liability. If theactual fuel and purchased power costs are higher or lower than the base fueland purchased power costs billed to customers, 95% of these amounts will be recoveredor refunded to our customers when the fuel adjustment clause is modified. On April 1,2009, we filed proposed rate schedules with the MPSC requesting an increase of$1.9 million in revenues for the under recovered

 

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fuel costs recognized for the six month period ended February 28,2009. This increase in revenue was approved by the MPSC on May 21, 2009,became effective June 1, 2009 and will be billed through our fueladjustment clause.

 

The MPSC order in the rate case approved aStipulation and Agreement providing for the recovery of deferred expenses ofapproximately $14.2 million over a five year period for the 2007 ice storms. Inaddition, the MPSC order required the implementation of a two-way trackingmechanism for recovery of the costs relating to the new MPSC rules oninfrastructure inspection and vegetation management. The mechanism authorizedby the MPSC creates a regulatory liability in any year we spend less than thetarget amount, which has been set at $8.6 million for our Missourijurisdiction, and a regulatory asset if we spend more than the target amount. Anyregulatory asset and liability amounts created using the tracking mechanismwill then be netted against each other and taken into account in our next ratecase. The MPSC also approved Stipulations and Agreements providing for thecontinuation of the pension and other post-retirement employee benefitstracking mechanism established in our 2006 and 2007 Missouri rate orders.

 

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

 

On October 2, 2008, the OPC andintervenors Praxair, Inc. and Explorer Pipeline Company filed Petitions forWrit of Review with the Cole County Circuit Court. These actions were consolidated into oneproceeding, and briefs have been filed with the Cole County Circuit Court.

 

*2006 Rate Case*

 

Allpending applications for rehearing in our Missouri 2006 rate case were deniedby the MPSC on November 20, 2008. On December 15, 2008, the OPC fileda Petition for Writ of Review with the Cole County Circuit Court regarding theMPSC’s decisions in our 2006 rate case. Praxair and Explorer Pipeline filed aPetition for Writ of Review on December 19, 2008. These actions wereconsolidated into one proceeding. Briefs have been filed by all parties andoral arguments were held on June 2, 2009.

 

OnMay 13, 2009, the OPC filed a petition in the Jasper County Circuit Courtseeking refunds with regard to utility rates for electric service paid by ourcustomers during the period of January 1, 2007 to December 13, 2007.During this period, we charged the rates set forth in the tariffs which wereapproved by, and are on file with, the MPSC. We filed a motion to dismiss, or,in the alternative, motion for more definitive statement. Oral arguments arescheduled for August 28, 2009.

 

*Kansas*

 

TheKansas Corporation Commission (KCC) approved a Joint Stipulated SettlementAgreement on December 9, 2005 effective January 4, 2006, in relationto our last Kansas rate case. Pursuant to the Agreement, we sought KCC approvalof an explicit natural gas hedging program in a separate docket by March 1,2006. We requested and received an extension until April 1, 2006 and madethis filing on March 30, 2006, which was denied in a February 4, 2008order by the KCC. As a result, all gains or losses related to the financialinstruments used to fix the future price of natural gas will be excluded fromthe Energy Cost Adjustment clause implemented in the last Kansas rate case andfuture base electric rates in Kansas.

 

***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

 

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recoveryof the ongoing cost of operating and maintaining our 1,200-mile gasdistribution system and a return on equity of 11.3%. Results from this casewould likely take effect in the second quarter of 2010.

 

**COMPETITION**

 

***Electric Segment***

 

*SPP-RTO*

 

OnFebruary 1, 2007, the Southwest Power Pool (SPP) regional transmissionorganization (RTO) launched its energy imbalance services market (EIS). Ingeneral, the SPP RTO EIS market provides real time energy for mostparticipating members within the SPP regional footprint. Imbalance energyprices are based on market bids and status/availability of dispatchablegeneration and transmission within the SPP market footprint. In addition toenergy imbalance service, the SPP RTO performs a real time security-constrained****economic dispatch of allgeneration voluntarily offered into the EIS market to the market participantsto also serve the native load.

 

TheSPP and its members have been evaluating the costs and benefits on expandingthe EIS market into a full day ahead energy market with a co-optimizedancillary services market, which will include the consolidation of all SPPbalancing authorities, including ours, into a single SPP balancing authority.On April 28, 2009, the SPP Regional State Committee (SPP RSC), whosemembers include state commissioners from our four state commissions, and theSPP Board of Directors (SPP BOD) endorsed a cost benefit report thatrecommended the SPP RTO move forward with the development of a day-ahead marketwith unit commitment and co-optimized ancillary services market (Day-AheadMarket) and implement the complete Day-Ahead Market as soon as practical, whichis anticipated in late 2012 or early 2013. As part of the Day-Ahead Market, theSPP RTO will create, prior to implementation of such market, a single NERCapproved balancing authority to take over balancing authority responsibilitiesfor its members, including us, which is expected to provide operational andeconomic benefits for us and our customers. The implementation of the Day-AheadMarket will replace the existing EIS market, which to date has, and is expectedto continue to, provide benefits for our customers.

 

OnAugust 15, 2008, the SPP filed with the FERC proposed revisions to itsopen access transmission pro forma tariff (OATT) to establish a process forincluding a “balanced portfolio” of economic transmission upgrades in theannual SPP Transmission Expansion Plan. The cost of such upgrades will berecovered through a regional rate allocated to SPP members based on their loadratio share within SPP’s market area of the balanced portfolio’s cost. On October 16,2008, the FERC accepted the balanced portfolio approach, which sets forth the selectionprocess of a group of projects and regional cost allocation rules based onprojected benefits and allocated costs over a ten year period. The plan will bebalanced if the portfolio is cost beneficial for each zone, including ours,within the SPP. A balanced portfolio could include projects below the 345 kvlevel (which is the bright line voltage level for projects to be included inthe portfolio) to increase benefits to a particular zone to achieve balance ofbenefits and costs over the ten year study period. On April 28, 2009, theSPP RSC and the SPP BOD approved the first set of balanced portfolio extra highvoltage transmission projects to be constructed within the SPP region. Thetransmission expansion projects, totaling over $700 million, include projectsin Missouri, Kansas, Arkansas, Oklahoma, Nebraska and Texas. We anticipate thisset of transmission expansion projects will provide long term benefits to ourcustomers yet expect our share of the net allocated costs to be immaterial.Also on April 28, 2009, the SPP RSC and BOD approved a new report thatrecommends restructuring of the SPP’s regional planning processes, which wouldestablish an integrated planning process for reliability, transmission serviceand economic transmission projects, based on a new set of planning principlesthat focus on the construction of a more robust transmission system largeenough in both scale and geography to provide flexibility to meet SPP members’and customers’ future needs. We will actively participate in the development ofthese new processes as well as cost allocation and recovery issues withmembers, prospective customers and the state commission representatives to theSPP RSC.

 

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*FERC Market Power Order*

 

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

 

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

 

Asa result of the FERC’s requirement for us to issue the aforementioned refundsand our belief that the FERC erred in its orders, on June 30, 2008 weinitiated a Petition For Review of the FERC’s orders on our market based raterefunds in the United States Court of Appeals for the District of****Columbia Circuit (DCCircuit). We requested and received approval for a consolidation of ourPetition with a similar petition by Westar Energy. On June 12, 2009, theDC Circuit denied our and Westar’s Petition for FERC to review its Orderrequiring the refunds to be made, concluding our efforts to recover the refundspaid.

 

Aspart of our market based pricing authority, we are required to conduct a marketpower analysis within our service territory and within the SPP RTO region everythree years. We anticipate that our next filing will occur during the thirdquarter of 2009 and will not show any material changes to our market positionand existing market based rate authority.

 

*Other FERC Activity*

 

OnJune 21, 2007, the FERC issued an Advance Notice of Proposed Rulemaking(ANOPR) on potential reforms to improve operations in organized wholesale powermarkets, such as the SPP RTO in which we participate. On October 16, 2008,the FERC issued its Final Order on Wholesale Competition in Regions withOrganized Electric Markets. The Final Order will affect us as it directlyaffects the SPP RTO. The Final Order addresses four key areas for amending itsregulations in Wholesale Competition for RTOs and Independent System Operators(ISOs): (1) demand response and market pricing during periods of operatingreserve shortage; (2) long-term power contracting; (3) marketmonitoring policies; and (4) the responsiveness of RTOs and ISOs tostakeholders and customers. We will be involved in the SPP RTOs discussions oncompliance 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, are requiredto submit a notification filing if there has been a material change in factsthat may affect the basis on which a public utility’s waiver was premised. TheStandards of Conduct generally govern the communications between our day to daytransmission operations personnel and our day to day wholesale marketing andsales personnel. We submitted our filing on July 13, 2009 in which webelieve continuation of our waiver, issued in 1997 and reaffirmed in 2004, isappropriate and reasonable. Based on the May 21, 2009 order, it ispossible that the FERC will

 

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revokeour waiver which would impact communication between our transmission andwholesale marketing and sales functions and operations within our organization.As part of our filing, we sought a twelve month extension in order to complywith the Standard of Conduct requirements in the event the FERC determined thatrevoking our waiver was appropriate. The FERC’s decision on this and otherStandard of Conduct waiver filings is expected during the third quarter of2009.

 

**LIQUIDITY AND CAPITALRESOURCES**

 

Weused approximately $84.5 million of cash for capital expenditures during thesix months ended June 30, 2009. Our primary source of cash for theseexpenditures during the six months ended June 30, 2009 was $60.0 millionin cash provided by operating activities. As of June 30, 2009, our workingcapital was negative (current liabilities exceeded current assets), primarilydue to the reclassification of $70 million of long-term debt to reflect itscurrent maturity and the continued use of short-term debt to fund ourconstruction program. Our current maturities include $20 million due November 1,2009 and $50 million due April 1, 2010. We expect to refinance thelong-term debt and continue to use short-term debt under our unsecured creditagreements. We also have an equity distribution program in place which isdesigned to provide additional funds from the issuance of equity from time totime.

 

**Summaryof Cash Flows (in millions)**

 
| ** **                               | ** ** | **Six Months Ended June 30,** | ** ** |
|------------------------------------------|------------|-------------------------------|------------|
| ** **                               | ** ** | **2009**                      | ** ** | **2008** | ** ** |
| Cash  provided by (used in):             |       |                          |       |   |   |
| Operating  activities                    |       | $                             | 60.0       |   | $ | 66.1 |   |
| Investing  activities                    |       | (84.0                         | )          | (114.2 | ) |
| Financing  activities                    |       | 24.6                          |       | 47.4 |   |
| Net  change in cash and cash equivalents |       | $                             | 0.6        |   | $ | (0.7 | ) |

 

**OperatingActivities**

 

Ournet cash flows provided by continuing operating activities were $60.0 millionduring the six months ended June 30, 2009 as compared to $66.1 million forthe six months ended June 30, 2008. This $6.1 million decrease wasprimarily due to changes in the level of accounts payable. In the six monthperiod ended June 30, 2008, we received $17.7 million in collateral fromone of our counterparties. This collateral was refunded subsequent to June 30,2008 and no comparable receipt of cash took place in the six month period endedJune 30, 2009. The effect of this change in accounts payable was offset bypositive cash effects of $6.7 million in higher net income and increases to netincome for non cash expenses, including deferred income taxes and non-cashlosses on derivatives settling through our margin accounts.

 

**CapitalRequirements and Investing Activities**

 

Ournet cash flows provided by investing activities decreased $30.2 million duringthe six months ended June 30, 2009 to $84.0 million as compared to $114.2million in the six months ended June 30, 2008 and decreased $10.5 millionto $42.4 million in the second quarter of 2009 as compared to $52.9 million inthe second quarter of 2008. This change occurred primarily due to a decrease incapital expenditures. The 2008 capital expenditures reflect cash outlays forthe December 2007 ice storm. These expenditures were incurred in 2007 butpaid in the first quarter of 2008. In addition, expenditures for new generationand distribution and transmission system additions are lower this year thanlast. Partially offsetting the capital expenditures during the six months endedJune 30, 2009 were proceeds from the sale of land totaling $0.5 million.

 

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A breakdown of the capital expenditures for the quarter and six monthsended June 30, 2009 is as follows:

 
| ** **                                                   | ** ** | **Capital Expenditures** | ** ** |
|--------------------------------------------------------------|------------|--------------------------|------------|
| ** **                                                   | ** ** | **Quarter Ended**        | ** ** | **Six Months Ended** | ** ** |
| **(in millions)**                                            | ** ** | **June 30, 2009**   | ** ** | **June 30, 2009** | ** ** |
| Distribution  and transmission system additions              |       | $                        | 7.0        |   | $ | 17.2 |   |
| New  Generation – Plum Point Energy Station             |       | 4.0                      |       | 9.0 |   |
| New  Generation – Iatan 2                               |       | 15.3                     |       | 31.5 |   |
| Storms                                                       |       | 6.0                      |       | 6.3 |   |
| Additions  and replacements – electric plant            |       | 8.7                      |       | 17.5 |   |
| Gas  segment additions and replacements                      |       | 0.4                      |       | 0.8 |   |
| Transportation                                               |       | 0.6                      |       | 0.8 |   |
| Other  (including retirements and salvage -net) (1)          |       | (0.9                     | )          | (1.6 | ) |
| **Subtotal**                                                 |       | 41.1                     |       | 81.5 |   |
| Non-regulated  capital expenditures (primarily fiber optics) |       | 0.2                      |       | 0.8 |   |
| **Subtotal capital expenditures incurred (2)**               |       | 41.3                     |       | 82.3 |   |
| Adjusted  for capital expenditures payable (3)               |       | 1.3                      |       | 2.2 |   |
| **Total cash outlay**                                        |       | $                        | 42.6       |   | $ | 84.5 |   |

 

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(1) Otherincludes equity AFUDC of $(2.6) million.

(2) Expendituresincurred represent the total cost for work completed for the projects duringthe quarter. Discussion of capital expenditures throughout this 10-Q ispresented on this basis.These capital expenditures include AFUDC,capital expenditures to retire assets and benefits from salvage.

(3) Represents the change in unpaid capitalexpenditures since the beginning of the year which is not reflected in theInvesting Activities section of the Statement of Cash Flows.

 

Approximately25% of our cash requirements for capital expenditures during the second quarterof 2009 were satisfied internally from operations (funds provided by operatingactivities less dividends paid). The remaining amounts of such requirementswere satisfied from short-term borrowings and proceeds from our sales of commonstock and debt securities discussed below

 

Weestimate that internally generated funds will provide approximately 43% of thefunds required for the remainder of our budgeted 2009 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, our 401(k) Plan and ESOP and our equity distribution agreement) tofinance additional amounts needed beyond those provided by operating activitiesfor such capital expenditures. We will continue to utilize short-term debt asneeded to support normal operations or other temporary requirements. Forfurther information see Note 6 of “Notes to Consolidated Financial Statements(Unaudited).”

 

**FinancingActivities**

 

Ournet cash flows provided by financing activities decreased $22.8 million to$24.6 million in 2009 as compared to $47.4 million in 2008 primarily due tolower financing needs as a result of the decrease in capital expendituresdiscussed above. Our 2009 financing needs were satisfied as set forth below.

 

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.

 

OnFebruary 25, 2009, we entered into an equity distribution agreement withUBS Securities LLC (UBS). Under the terms of the agreement, we may offer andsell shares of our common stock, par value $1.00 per share, having an aggregateoffering price of up to $60 million from time to time through UBS, as salesagent. We intend to use the net proceeds from this equity distribution programto repay short-term debt and for general corporate purposes, including to fundour current construction program. During the second quarter of 2009, we issuedand sold 6,400 shares pursuant to this program, at an average price per shareof $16.50, resulting in proceeds to us of approximately $0.1 million (afterpayment of approximately $4,489 in commissions to the sales agent). Through July 31,2009, in the aggregate, we have issued and sold 200,519 shares pursuant to theprogram, resulting in net proceeds to us of approximately $3.2 million.

 

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Sales of the shares pursuantto the equity distribution agreement will be made at market prices or asotherwise agreed with UBS. Under the terms of the program agreement, we mayalso sell shares to UBS as principal for UBS’ own account at a price agreedupon at the time of sale.

 

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, 2009, in addition to amounts remaining underthe equity distribution program described above, $265 million remains availablefor issuance under this shelf registration statement. Of the original $400million, $250 million was available for first mortgage bonds with $175 millionremaining available after the issuance of $75 million in first mortgage bondson March 27, 2009. We plan to use a portion of the proceeds from issuancesunder this shelf to fund a portion of the capital expenditures for our newgeneration projects.

 

OnMarch 11, 2009, we entered into a $50 million unsecured credit agreement.This agreement provides for $50 million of revolving loans to be available tous for working capital, general corporate purposes and to back-up our use ofcommercial paper and terminates on July 15, 2010. This credit agreement isin addition to, and has substantially identical covenants and terms as (otherthan pricing), our Amended and Restated Unsecured Credit Agreement dated March 14,2006 discussed below. There were no borrowings under this agreement at June 30,2009.

 

OnJuly 15, 2005, we entered into a $150 million unsecured revolving creditfacility until July 15, 2010. Borrowings (other than through commercialpaper) are at the bank’s prime commercial rate or LIBOR plus 100 basis pointsbased on our current credit ratings and the pricing schedule in the line ofcredit facility. On March 14, 2006, we entered into the First Amended andRestated Unsecured Credit Agreement which amends and restates the $150 millionunsecured revolving credit facility. The principal amount of the creditfacility was increased to $226 million, with the additional $76 millionallocated to support a letter of credit issued in connection with ourparticipation in the Plum Point Energy Station project. This extra $76 millionof availability reduces over a four year period in line with the amount ofconstruction expenditures we owe for Plum Point Unit 1 and was $12.5 million asof August 1, 2009. The unallocated credit facility is used for workingcapital, general corporate purposes and to back-up our use of commercial paper.This facility requires our total indebtedness (which does not include our notepayable to the securitization trust) to be less than 62.5% of our totalcapitalization at the end of each fiscal quarter and our EBITDA (defined as netincome plus interest, taxes, depreciation and amortization) to be at least twotimes our interest charges (which includes interest on the note payable to thesecuritization trust) for the trailing four fiscal quarters at the end of eachfiscal quarter. Failure to maintain these ratios will result in an event ofdefault under the credit facility and will prohibit us from borrowing fundsthereunder. As of June 30, 2009, we are in compliance with these ratios.This credit facility is also subject to cross-default if we default on inexcess of $10 million in the aggregate on our other indebtedness. Thisarrangement does not serve to legally restrict the use of our cash in thenormal course of operations. There were $51.0 million of outstanding borrowingsunder this agreement at June 30, 2009. In addition, $21.0 million of theavailability thereunder was used at such date to back up our outstandingcommercial paper.

 

Theprincipal amount of all series of first mortgage bonds outstanding at any onetime under the EDE Mortgage is limited by terms of the mortgage to $1 billion.Substantially all of the property, plant and equipment of The Empire DistrictElectric Company (but not its subsidiaries) is subject to the lien of the EDEMortgage.****Restrictions inthe EDE mortgage bond indenture could affect our liquidity. The EDE Mortgagecontains a requirement that for new first mortgage bonds to be issued, our netearnings (as defined in the EDE Mortgage) for any twelve consecutive monthswithin the fifteen months preceding issuance must be two times the annualinterest requirements (as defined in the EDE Mortgage) on all first mortgagebonds then outstanding and on the prospective issue of new first mortgagebonds. Our earnings for the twelve months ended June 30, 2009 would permitus to issue approximately $291.2 million of new first mortgage bonds based onthis test with an assumed interest rate of 7.0%. In addition to the interestcoverage requirement, the EDE Mortgage provides that new bonds must be issuedagainst, among other things, retired bonds or 60% of net property additions. AtJune 30, 2009, we had retired bonds and net property additions which would

 

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enablethe issuance of at least $608.8 million principal amount of bonds if the annualinterest requirements are met. As of June 30, 2009, we are in compliancewith all restrictive covenants of the EDE Mortgage.

 

Theprincipal amount of all series of first mortgage bonds outstanding at any onetime under the EDG Mortgage is limited by terms of the mortgage to $300million. Substantially all of the property, plant and equipment of The EmpireDistrict Gas Company is subject to the lien of the EDG Mortgage. The EDGMortgage contains a requirement that for new first mortgage bonds to be issued,the amount of such new first mortgage bonds shall not exceed 75% of the cost ofproperty additions acquired after the date of the Missouri Gas acquisition. Themortgage also contains a limitation on the issuance by EDG of debt (includingfirst mortgage bonds, but excluding short-term debt incurred in the ordinarycourse under working capital facilities) unless, after giving effect to 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 30,2009, this test would not allow us to issue new first mortgage bonds.

 

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

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

 

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*****Not rated

******Insured by a third partyinsurer.

 

**CONTRACTUAL OBLIGATIONS**

 

Our contractual obligationshave not significantly changed at June 30, 2009, compared to December 31,2008 other than the $75 million principal amount of 7% first mortgage bondsissued on March 27, 2009 and due April 1, 2024 and related interestcosts.

 

**DIVIDENDS**

 

Holdersof our common stock are entitled to dividends if, as, and when declared by theBoard of Directors, out of funds legally available therefore, subject to theprior rights of holders of any outstanding cumulative preferred stock andpreference stock. Payment of dividends is determined by our Board of Directorsafter considering all relevant factors, including the amount of our retainedearnings (which is essentially our accumulated net income less dividend payouts).As of June 30, 2009 our retained earnings balance was $10.3 million,compared to $7.4 million as of June 30, 2008, after paying out $11.0million in dividends during the second quarter of 2009. A reduction of ourdividend per share, partially or in whole, could have an adverse effect on ourcommon stock price. On July 23, 2009, the Board of Directors declared aquarterly dividend of $0.32 per share on common stock payable September 15,2009 to holders of record as of September 1, 2009.

 

Our diluted earnings pershare were $0.54 for the six months ended June 30, 2009 and were $1.17 and$1.09 for the years ended December 31, 2008 and 2007, respectively.Dividends paid per share were $0.64 for the six months ended June 30, 2009and $1.28 for each of the years ended December 31, 2008 and 2007.

 

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

 

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anyother distribution on, or purchase (other than with the proceeds of additionalcommon stock financing) any shares of, our common stock if the cumulativeaggregate amount thereof after August 31, 1944 (exclusive of the firstquarterly dividend of $98,000 paid after said date) would exceed the sum of$10.75 million and the earned surplus (as defined in the EDE Mortgage)accumulated subsequent to August 31, 1944, or the date of succession inthe event that another corporation succeeds to our rights and liabilities by amerger or consolidation. On March 11, 2008, we amended the EDE Mortgage inorder to provide us with more flexibility to pay dividends to our shareholdersby increasing the basket available to pay dividends by $10.75 million, asdescribed above. As of June 30, 2008, this restriction did not prevent usfrom issuing dividends.

 

Inaddition, under certain circumstances, our Junior Subordinated Debentures,8-1/2% Series due 2031, reflected as a note payable to securitizationtrust on our balance sheet, held by Empire District Electric Trust I, anunconsolidated securitization trust subsidiary, may also restrict our abilityto pay dividends on our common stock. These restrictions apply if: (1) wehave knowledge that an event has occurred that would constitute an event ofdefault under the indenture governing these junior subordinated debentures andwe have not taken reasonable steps to cure the event, (2) we are indefault with respect to payment of any obligations under our guarantee relatingto the underlying preferred securities, or (3) we have deferred interestpayments on the Junior Subordinated Debentures, 8-1/2% Series due 2031 orgiven notice of a deferral of interest payments. As of June 30, 2008,there were no such restrictions on our ability to pay dividends.

 

**OFF-BALANCE SHEET ARRANGEMENTS**

 

Wehave no off-balance sheet arrangements that have or are reasonably likely to havea current or future effect on our financial condition, changes in financialcondition, revenues or expenses, results of operations, liquidity, capitalexpenditures or capital resources, other than operating leases entered into inthe normal course of business.

 

**CRITICAL ACCOUNTING POLICIES**

 

*Goodwill.**             *We recorded goodwill of$39.5 million upon the completion of the 2006 Missouri Gas acquisition.Goodwill represents the excess of the cost of the acquisition over the fairvalue of the related net assets at the date of acquisition. In accordance withStatement of Financial Accounting Standards No. 142, “Goodwill and OtherIntangible Assets,” (FAS 142) goodwill is required to be tested for impairmenton an annual basis or whenever events or circumstances indicate possibleimpairment. In performing impairment tests, we utilize valuation techniqueswhich estimate the discounted future cash flows of operations. Our proceduresinclude developing a baseline test and performing sensitivity analysis tocalculate a reasonable valuation range. The sensitivities are derived fromaltering those assumptions which are subjective in nature and inherent to adiscounted cash flows valuation technique. Other qualitative factors andcomparisons to industry peers are also used to further support the assumptionsand ultimately the overall evaluation. A significant qualitative factorconsidered in our evaluation is the impact of regulation, including rateregulation and cost recovery for our gas segment. Some of the more significantquantitative assumptions included in our tests involve: regulatory rate designand results; the discount rate; the growth rate; capital spending rates andterminal value calculations. Risks and uncertainties affecting theseassumptions include:  management’sidentification of impairment indicators, changes in business, industry, laws,technology or economic and market conditions. While management believes theassumptions utilized in our analysis were reasonable, significant adversedevelopments in the gas segment in future periods or changes in the assumptionscould negatively impact goodwill impairment considerations, which couldadversely impact earnings. We performed our annual goodwill impairment test asof November 30, 2008 and concluded our goodwill was not impaired. Thistest estimated the fair market value of our gas segment to be 10-15% higherthan its carrying value at that time. We do not believe the fair value of ourgas segment declined below the carrying value during the quarter ended June 30,2009 and as a result an interim test for impairment was not performed.

 

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See“Item 7 – Managements Discussion and Analysis of Financial Condition andResults of Operations” in our Annual Report Form 10-K for the year ended December 31,2008 for a discussion of our other critical accounting policies. There were nochanges in these policies in the quarter ended June 30, 2009.

 

**RECENTLY ISSUED ACCOUNTING STANDARDS**

 

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

 

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

 

Our fuel procurement activities involve primary market risk exposures,including commodity price risk and credit risk. Commodity price risk is thepotential adverse price impact related to the fuel procurement for ourgenerating units. Credit risk is the potential adverse financial impactresulting from non-performance by a counterparty of its contractualobligations. Additionally, we are exposed to interest rate risk which is 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 60.9% of our2008 generation fuel supply need through coal. Approximately 90% of our 2008coal supply was Western coal. We have contracts to supply a portion of the fuelfor our coal plants through 2013. These contracts satisfy approximately 89% ofour anticipated fuel requirements for 2009, 75% for 2010, 58% for 2011, 27% for2012 and 30% of our 2013 requirements for our Asbury and Riverton coal plants.In order to manage our exposure to fuel prices, future coal supplies will beacquired using a combination of short-term and long-term contracts.

 

Weare exposed to changes in market prices for natural gas we must purchase to runour combustion turbine generators. Our natural gas procurement program isdesigned to manage our costs to avoid volatile natural gas prices. We enterinto physical forward and financial derivative contracts with counterpartiesrelating to our future natural gas requirements that lock in prices (withrespect to predetermined percentages of our expected future natural gas needs)in an attempt to lessen the volatility in our fuel expenditures and improvepredictability. As of July 24, 2009, 92%, or 4.3 million Dths, of ouranticipated volume of natural gas usage for our electric operations for theremainder of 2009 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, 2009, our natural gas cost would increase byapproximately $0.9 million based on our June 30, 2009 total hedgedpositions for the next twelve months. However, such an increase would beprobable of recovery through fuel adjustment mechanisms.

 

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Weattempt to mitigate a portion of our natural gas price risk associated with ourgas segment using physical forward purchase agreements, storage and derivative contracts.As of July 24, 2009, we have 1.2 million Dths in storage on the threepipelines that serve our customers. This represents 60% of our storagecapacity. Our long-term hedge strategyis to mitigate price volatility for our customers by hedging a minimum of 50%of current year, up to 50% of the second year and up to 20% of third yearexpected gas usage by the beginning of the ACA year at September 1. However, due to purchased natural gascost recovery mechanisms for our retail customers, fluctuations in the cost ofnatural gas have little effect on income.

 

*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, whichis typically the result of changes in commodity prices. Amounts reported asmargin 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 by various trading counterparties that resulted from us exceedingagreed-upon credit limits established by the counterparties. The followingtable depicts our margin deposit assets and margin deposit liabilities at June 30,2009 and December 31, 2008:

 
| **(in millions)**           | ** ** | **June 30, 2009** | ** ** | **December 31, 2008** | ** ** |
|-----------------------------|------------|------------------------|------------|----------------------------|------------|
| Margin  deposit assets      |       | $                      | 4.9        |                       | $          | 10.7 |   |
| Margin  deposit liabilities |       | $                      | —     |                       | $          | — |   |

 

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 30,2009, 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 |       | $          | 8.1        |   |
| Net  unrealized mark-to-market losses for financial natural gas contracts        |       | 6.1        |       |
| **Net credit exposure**                                                          | ** ** | **$**      | **14.2**   | ** ** |

 

The$6.1 million net unrealized mark-to-market loss for financial natural gascontracts is comprised of $9.9 million of exposure to counterparties of Empirefor unrealized losses and $3.8 million of exposure to Empire of unrealizedgains from a single counterparty. We are holding no collateral from thiscounterparty since we are below the $10 million mark-to-market collateral thresholdin our agreement with this counterparty. As noted above, we have $4.9 millionon deposit with NYMEX covering counterparty exposure to Empire. In addition, if NYMEX gas prices decreased25% from their July 24, 2009 levels, we would be required to post anadditional $1.1 million in collateral. If these prices increased 25%, ourcollateral requirement would decrease $1.6 million.

 

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

 

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

 

**Item 4.  Controls andProcedures**

 

Asof the end of the period covered by this report, an evaluation was carried out,under the supervision and with the participation of our management, includingour Chief Executive Officer and Chief Financial Officer, of the effectivenessof the design and operation of our disclosure controls and procedures (as suchterm is defined in Rule 13a-15(e) of the Securities Exchange Act of1934). Based upon that evaluation, the Chief Executive Officer and Chief FinancialOfficer concluded that our disclosure controls and procedures were effective asof June 30, 2009.

 

There have been no changes in our internal control over financialreporting that occurred during the second quarter of 2009 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 Plaintiff crops due toinappropriate management of the levee system around Iatan. No proceduralschedule has been established and we are unable to predict the outcome of thelaw suit.

 

**Item 1A.  Risk Factors.**

 

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

 

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

 

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

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

 

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*Notrated.

**Insuredby a third party insurer.

 

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Theratings indicate the agencies’ assessment of our ability to pay interest,distributions and principal on these securities. A rating is not arecommendation to purchase, sell or hold securities and each rating should beevaluated independently of any other rating. The lower the rating, the higherthe interest cost of the securities when they are sold. In addition, adowngrade in our senior unsecured long-term debt rating would result in anincrease in our borrowing costs under our bank credit facility. If any of ourratings fall below investment grade (investment grade is defined as Baa3 orabove for Moody’s and BBB- or above for Standard & Poor’s and Fitch),our ability to issue short-term debt, commercial paper or other securities orto market those securities would be impaired or made more difficult orexpensive. Therefore, any such downgrades could have a material adverse effecton our business, financial condition and results of operations. In addition,any actual downgrade of our commercial paper rating from Moody’s or Fitch, maymake it difficult for us to issue commercial paper. To the extent we are unableto issue commercial paper, we will need to meet our short-term debt needsthrough borrowings under our revolving credit facilities, which may result inhigher costs.

 

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

 

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

 

Therecent general market declines resulting in part from the sub-prime mortgageissues have generally reduced access to the capital markets and reduced marketreturns on investments. We estimate our capital expenditures to be $168.9million in 2009. Although we believe it is unlikely we will have difficultyaccessing the markets for the capital needed to complete these projects, ourfinancing costs will likely be higher when compared to previous years. Themarket’s effect on our pension plan assets resulted in a negative return of25.1% in 2008. This decline will likely result in increased fundingrequirements under the Pension Protection Act of 2006.

 

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

 

Fueland purchased power costs are our largest expenditures. Increases in the priceof coal, natural gas or the cost of purchased power will result in increasedelectric operating expenditures.

 

Wedepend upon regular deliveries of coal as fuel for our Riverton, Asbury andIatan plants, and as fuel for the facility which supplies us with purchasedpower under our contract with Westar Energy. Substantially all of this coalcomes from mines in the Powder River Basin of Wyoming and is delivered to theplants by train. Production problems in these mines, railroad transportation orcongestion problems, such as those that occurred in 2005 and 2006, orunavailability of trains could affect delivery cycle times required to maintainplant inventory levels, causing us to implement coal conservation and supplyreplacement measures to retain adequate reserve inventories at our facilities.These measures could include some or all of the following:  reducing the output of our coal plants, increasingthe utilization of our higher-cost gas-fired generation facilities, purchasingpower from other suppliers, adding additional leased trains to our supplysystem and purchasing locally mined coal which can be delivered without usingthe railroads. Such measures could result in increased fuel and purchased powerexpenditures.

 

Withthe addition of the Missouri fuel adjustment mechanism effective September 1,2008, we now have a fuel cost recovery mechanism in all of our jurisdictions,which significantly reduces our net income exposure to the impact of the risksdiscussed above. However, cash flow could still be impacted by these increasedexpenditures. We are also subject to prudency reviews which could negativelyimpact our net income if a regulatory commission would conclude our costs wereincurred imprudently.

 

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Wehave also established a risk management practice of purchasing contracts forfuture fuel needs to meet underlying customer needs and manage cost and pricinguncertainty. Within this activity, we may incur losses from these contracts. Byusing physical and financial instruments, we are exposed to credit risk andmarket risk. Market risk is the exposure to a change in the value ofcommodities caused by fluctuations in market variables, such as price. The fairvalue of derivative financial instruments we hold is adjusted cumulatively on amonthly basis until prescribed determination periods. At the end of eachdetermination period, which is the last day of each calendar month in theperiod, any realized gain or loss for that period related to the contract willbe reclassified to fuel expense and recovered or refunded to the customerthrough our fuel adjustment mechanisms. Credit risk is the risk that thecounterparty might fail to fulfill its obligations under contractual terms.

 

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

 

Weare subject to comprehensive regulation by federal and state utility regulatoryagencies, which significantly influences our operating environment and ourability to recover our costs from utility customers. The utility commissions inthe states where we operate regulate many aspects of our utility operations,including the rates that we can charge customers, siting and construction offacilities, pipeline safety and compliance, customer service and our ability torecover increases in our fuel and purchased power costs.

 

TheFERC has jurisdiction over wholesale rates for electric transmission serviceand electric energy sold in interstate commerce. Federal, state and localagencies also have jurisdiction over many of our other activities.

 

Informationconcerning recent filings requesting increases in rates and related matters isset forth under Item 7, “Management’s Discussion and Analysis of FinancialCondition and Results of Operations — Rate Matters.”

 

Weare unable to predict the impact on our operating results from the regulatoryactivities of any of these agencies. Despite our requests, these regulatorycommissions have sole discretion to leave rates unchanged, grant increases ororder decreases in the base rates we charge our utility customers. They havesimilar authority with respect to our recovery of increases in our fuel andpurchased power costs. If our costs increase and we are unable to recoverincreased costs through base rates or fuel adjustment clauses, or if we areunable to fully recover our investments in new facilities, our results ofoperations could be materially adversely affected. Changes in regulations orthe imposition of additional regulations could also have a material adverseeffect on our results of operations.

 

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

 

Theoperation of our electric generation, and electric and gas transmission anddistribution systems involves many risks, including breakdown or failure ofexpensive and sophisticated equipment, processes and personnel performance;operating limitations that may be imposed by equipment conditions,environmental or other regulatory requirements; fuel supply or fuel transportationreductions or interruptions; transmission scheduling constraints; and catastrophicevents such as fires, explosions, severe weather or other similar occurrences.

 

Wehave implemented training, preventive maintenance and other programs, but thereis no assurance that these programs will prevent or minimize future breakdowns,outages or failures of our generation facilities. In those cases, we would needto either produce replacement power from our other facilities or purchase powerfrom other suppliers at potentially volatile and higher cost in order to meetour sales obligations.

 

Theseand other operating events may reduce our revenues, increase costs, or both,and may materially affect our results of operations, financial position andcash flows.

 

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

 

Theprimary drivers of our electric operating revenues in any period are:  (1) rates we can charge our customers, (2) weather,(3) customer growth and (4) general economic conditions. Of thefactors driving revenues, weather has the greatest short-term effect on the demandfor electricity for our regulated business. Mild weather reduces demand and, asa result, our electric operating revenues. In addition, changes in customerdemand due to downturns in the economy could reduce our revenues.

 

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

 

The primary drivers of our gas operating revenues inany period are: (1) rates we can charge our customers, (2) weather, (3) customergrowth, (4) the cost of natural gas and interstate pipeline transportationcharges and (5) general economic conditions. Because natural gas isheavily used for residential and commercial heating, the demand for thisproduct depends heavily upon weather patterns throughout our natural gasservice territory and a significant amount of our natural gas revenues arerecognized in the first and fourth quarters related to the heating seasons.Accordingly, our natural gas operations have historically generated lessrevenues and income when weather conditions are warmer in the winter.

 

The primary driver of our gas operating expense inany period is the price of natural gas.

 

Significantincreases in electric and gas operating expenses or reductions in electric andgas operating revenues may occur and result in a material adverse effect on ourbusiness, financial condition and results of operations.

 

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

 

Inour natural gas utility business, we are permitted to recover the cost of gasdirectly from our customers through the use of a purchased gas adjustmentprovision. Our purchased gas adjustment provision is regularly reviewed by theMissouri Public Service Commission (MPSC). In addition to reviewing ouradjustments to customer rates, the MPSC reviews our costs for prudency as well.To the extent the MPSC may determine certain costs were not incurred prudently,it could adversely affect our gas segment earnings and cash flows. In addition,increases in natural gas costs affect total prices to our customers and,therefore, the competitive position of gas relative to electricity and otherforms of energy. Increases in natural gas costs may also result in lower usageby customers unable to switch to alternate fuels. Such disallowed costs orcustomer losses could have a material adverse effect on our business, financialcondition and results of operations.

 

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

 

Weare subject to extensive federal, state and local regulation with regard to airand other environmental matters. Failure to comply with these laws andregulations could have a material adverse effect on our results of operationsand financial position. In addition, new environmental laws and regulations,and new interpretations of existing environmental laws and regulations, havebeen adopted and may in the future be adopted which may substantially increaseour future environmental expenditures for both new facilities and our existingfacilities. Compliance with current and future air emission standards (such asthose limiting emission levels of sulfur dioxide (SO2) and nitrogen oxide (NOx)and, potentially, carbon dioxide (CO2)) has required, and may in the futurerequire, significant environmental expenditures. Although we generally recoversuch costs through our rates, there can be no assurance that we will recoverall, or any part of, such increased costs in

 

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futurerate cases. The incurrence of additional material environmental costs which arenot recovered in our rates may result in a material adverse effect on ourbusiness, financial condition and results of operations.

 

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

 

Wehave entered into contracts to purchase an undivided interest in 50 megawatts(7.5% ownership interest) of the Plum Point Energy Station’s new 665-megawatt,coal-fired generating facility which is being built near Osceola, Arkansas. Wehave also entered into an agreement with Kansas City Power & LightCompany to purchase an undivided ownership interest in the coal-fired Iatan 2generating facility. We will own 12%, or approximately 100 megawatts, of the850-megawatt unit.

 

Thereare risks that actual costs may exceed budget estimates, delays may occur in obtainingpermits and materials, suppliers and contractors may not perform as requiredunder their contracts, there may be inadequate availability, productivity or increasedcost of qualified craft labor, start-up activities may take longer thancurrently planned, the scope and timing of projects may change, the re-baselinedschedule may not be met and other events beyond our control, including thefailure of one or more of the generation plant co-owners to pay their share ofconstruction, operations and maintenance costs, may occur that may materially affectthe schedule, budget, cost and performance of these projects. To the extent thecompletion of these projects is delayed, we expect that the timing of receiptof increases in base rates reflecting our investment in such projects will becorrespondingly delayed.

 

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

 

(a)           The Annual Meetingof Stockholders was held on April 23, 2009.

 

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

 

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

 

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

 

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

 

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

 

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

 

The term of office as Director of the following other Directorscontinued after the meeting:  William L.Gipson, Kenneth R. Allen, Bill D. Helton, Ross C. Hartley, Julio S. Leon, andAllan T. Thoms.

 

(c)                                  Commonstockholders voted to approve ratification of the appointment ofPricewaterhouseCoopers LLP as Empire’s independent registered public accountingfirm for the fiscal year ending December 31, 2009. Passage of the proposalrequired the affirmative vote of a majority of the votes cast. The proposalreceived 28,945,310 votes for and 359,096 votes against.

 

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**Item5.  Other Information.**

 

Forthe twelve months ended June 30, 2009, our ratio of earnings to fixedcharges was 2.33x.  See Exhibit (12)hereto.

 

**Item 6.  Exhibits.**

 

(a)           Exhibits.

 

(12) Computation of Ratio ofEarnings to Fixed Charges.

 

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

 

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

 

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

 

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

 

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

 

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**SIGNATURES**

 

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

 
|                 | **THE  EMPIRE DISTRICT ELECTRIC COMPANY** |
|----------------------|-------------------------------------------|
|                 | Registrant                                |
|                 |                                      |
|                 |                                      |
| ** **           | **By**                                    | **/s/ Gregory A. Knapp** |
|                 |                                      | Gregory A. Knapp |
|                 |                                      | Vice President – Finance and Chief Financial Officer |
| ** **           | ** **                                | ** ** |
| ** **           | ** **                                | ** ** |
| ** **           | **By**                                    | **/s/ Laurie A. Delano** |
|                 |                                      | Laurie A. Delano |
|                 |                                      | Controller, Assistant Secretary and Assistant Treasurer |
|                 |                                      |   |
| August 6,  2009 |                                      |   |

 

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