Tableof Contents

 

 

 

**UNITED STATESSECURITIES AND EXCHANGE COMMISSION**

**WASHINGTON,D.C. 20549**

 

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**FORM 10-Q**

 

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**(MarkOne)**

 

| **x**  | **Quarterly  report pursuant to Section 13 or 15(d) of the Securities Exchange  Act of 1934**  | ** ** |
|--------|----------------------------------------------------------------------------------------------------------|------------|
|   |                                                                                                     |       |
|   | **For the  quarterly period ended September 30, 2009**                                              | ** ** |
|   |                                                                                                     |       |
|   | **or**                                                                                                   | ** ** |
|   |                                                                                                     |       |
| **o**  | **Transition  report pursuant to Section 13 or 15(d) of the Securities Exchange  Act of 1934** | ** ** |

 

**For the transition period from                  to                  .**

 

**Commission file number: 1-3368**

 

**THE EMPIRE DISTRICT ELECTRICCOMPANY**

(Exact name of registrant as specified in its charter)

 

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

 

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

 

Indicate by checkmark whether the registrant (1) has filed all reports required to be filedby Section 13 or 15(d) of the Securities Exchange Act of 1934 duringthe preceding 12 months (or for such shorter period that the registrant wasrequired to file such reports), and (2) has been subject to such filingrequirements for the past 90 days.  Yes 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 check mark whether the registrant is alarge accelerated filer, an accelerated filer, a non-accelerated filer, or asmaller reporting company. See the definitions of “large accelerated filer,” “acceleratedfiler” 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 November 1,2009, 36,062,857 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                                                                      | 38       |
|          |                                                                                        |     |
|          | Rate  Matters                                                                               | 50       |
|          |                                                                                        |     |
|          | Competition                                                                                 | 52       |
|          |                                                                                        |     |
|          | Liquidity and Capital Resources                                                             | 54       |
|          |                                                                                        |     |
|          | Contractual  Obligations                                                                    | 57       |
|          |                                                                                        |     |
|          | Dividends                                                                                   | 57       |
|          |                                                                                        |     |
|          | Off-Balance Sheet Arrangements                                                              | 58       |
|          |                                                                                        |     |
|          | Critical Accounting Policies                                                                | 58       |
|          |                                                                                        |     |
|          | Recently Issued Accounting Standards                                                        | 59       |
|          |                                                                                        |     |
| Item 3.       | Quantitative  and Qualitative Disclosures About Market Risk                                 | 59       |
|          |                                                                                        |     |
| Item 4.       | Controls and  Procedures                                                                    | 61       |
|          |                                                                                        |     |
| Part II- | Other Information:                                                                          |     |
|          |                                                                                        |     |
| Item 1.       | Legal Proceedings                                                                           | 61       |
|          |                                                                                        |     |
| Item 1A.      | Risk Factors                                                                                | 62       |
|          |                                                                                        |     |
| 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 - (none)                               |     |
|          |                                                                                        |     |
| Item 5.       | Other Information                                                                           | 65       |
|          |                                                                                        |     |
| Item 6.       | Exhibits                                                                                    | 65       |
|          |                                                                                        |     |
|          | Signatures                                                                                  | 67       |

 

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**FORWARD LOOKING STATEMENTS**

 

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

 

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

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

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

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

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

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

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

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

·                  legislation;

·                  regulation, including environmentalregulation (such as NOx, SO2 and CO2 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 ouractual results, performance or achievements to differ materially from thefacts, results, performance or achievements we have anticipated in suchforward-looking statements.

 

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**PART I.  FINANCIAL INFORMATION**

 

**Item 1.  FinancialStatements**

 

**THEEMPIRE DISTRICT ELECTRIC COMPANY**

**CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)**

 
| ** **                                                                    | ** ** | **Three Months Ended**                     | ** ** |
|-------------------------------------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                                                    | ** ** | **September 30**                      | ** ** |
| ** **                                                                    | ** ** | **2009**                                   | ** ** | **2008** | ** ** |
| ** **                                                                    | ** ** | **(000’s except per share  amounts)** | ** ** |
| **Operating revenues:**                                                       | ** ** | ** **                                 |       |   |   |
| Electric                                                                      |       | $                                          | 121,487    |   | $ | 130,911 |   |
| Gas                                                                           |       | 4,795                                      |       | 6,056 |   |
| Water                                                                         |       | 474                                        |       | 484 |   |
| Other                                                                         |       | 1,297                                      |       | 1,234 |   |
|                                                                          |       | 128,053                                    |       | 138,685 |   |
| **Operating revenue deductions:**                                             | ** ** | ** **                                 |       |   |   |
| Fuel  and purchased power                                                     |       | 48,132                                     |       | 51,501 |   |
| Cost  of natural gas sold and transported                                     |       | 2,033                                      |       | 3,414 |   |
| Regulated  operating expenses                                                 |       | 18,854                                     |       | 18,404 |   |
| Other  operating expenses                                                     |       | 456                                        |       | 481 |   |
| Maintenance  and repairs                                                      |       | 8,206                                      |       | 7,051 |   |
| Depreciation  and amortization                                                |       | 13,034                                     |       | 13,393 |   |
| Provision  for income taxes                                                   |       | 6,894                                      |       | 9,861 |   |
| Other  taxes                                                                  |       | 6,767                                      |       | 6,561 |   |
|                                                                          |       | 104,376                                    |       | 110,666 |   |
|                                                                          |       |                                       |       |   |   |
| **Operating income**                                                          |       | 23,677                                     |       | 28,019 |   |
| **Other income and (deductions):**                                            | ** ** | ** **                                 |       |   |   |
| Allowance  for equity funds used during construction                          |       | 1,429                                      |       | 1,690 |   |
| Interest  income                                                              |       | 42                                         |       | 366 |   |
| Benefit/(provision)  for other income taxes                                   |       | 15                                         |       | (64 | ) |
| Other,  net                                                                   |       | (211                                       | )          | (327 | ) |
|                                                                          |       | 1,275                                      |       | 1,665 |   |
| **Interest charges:**                                                         |       |                                       |       |   |   |
| Long-term  debt                                                               |       | 10,911                                     |       | 9,565 |   |
| Note  payable to securitization trust                                         |       | 1,063                                      |       | 1,063 |   |
| Short-term  debt                                                              |       | 194                                        |       | 242 |   |
| Allowance  for borrowed funds used during construction                        |       | (1,911                                     | )          | (1,689 | ) |
| Other                                                                         |       | (134                                       | )          | 323 |   |
|                                                                          |       | 10,123                                     |       | 9,504 |   |
| ** **                                                                    |       |                                       |       |   |   |
| **Net income**                                                                |       | $                                          | 14,829     |   | $ | 20,180 |   |
| Weighted  average number of common shares outstanding - basic                 |       | 34,840                                     |       | 33,895 |   |
| Weighted  average number of common shares outstanding - diluted               |       | 34,887                                     |       | 33,930 |   |
| **Total earnings per weighted average share of  common stock – basic**   | ** ** | **$**                                      | **0.43**   |   | $ | 0.60 |   |
| **Total earnings per weighted average share of  common stock – diluted** | ** ** | **$**                                      | **0.43**   |   | $ | 0.59 |   |
| **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)**

 
|                                                                                    |       | **Nine Months Ended**                      |       |
|-----------------------------------------------------------------------------------------|------------|--------------------------------------------|------------|
|                                                                                    |       | **September 30,**                     |       |
|                                                                                    |       | **2009**                                   | ** ** | **2008** |   |
|                                                                                    |       | **(000’s except per share  amounts)** |       |
| **Operating revenues:**                                                                 | ** ** | ** **                                 |       |   |   |
| Electric                                                                                |       | $                                          | 330,498    |   | $ | 339,717 |   |
| Gas                                                                                     |       | 40,800                                     |       | 42,480 |   |
| Water                                                                                   |       | 1,333                                      |       | 1,361 |   |
| Other                                                                                   |       | 3,667                                      |       | 3,352 |   |
|                                                                                    |       | 376,298                                    |       | 386,910 |   |
| **Operating revenue deductions:**                                                       |       |                                       |       |   |   |
| Fuel  and purchased power                                                               |       | 136,470                                    |       | 155,385 |   |
| Cost  of natural gas sold and transported                                               |       | 25,552                                     |       | 26,412 |   |
| Regulated  operating expenses                                                           |       | 54,431                                     |       | 53,965 |   |
| Other  operating expenses                                                               |       | 1,287                                      |       | 1,307 |   |
| Maintenance  and repairs                                                                |       | 24,798                                     |       | 19,444 |   |
| Depreciation  and amortization                                                          |       | 38,446                                     |       | 40,875 |   |
| Provision  for income taxes                                                             |       | 16,455                                     |       | 14,951 |   |
| Other  taxes                                                                            |       | 20,500                                     |       | 19,667 |   |
|                                                                                    |       | 317,939                                    |       | 332,006 |   |
|                                                                                    |       |                                       |       |   |   |
| **Operating income**                                                                    |       | 58,359                                     |       | 54,904 |   |
| **Other income and (deductions):**                                                      | ** ** | ** **                                 |       |   |   |
| Allowance  for equity funds used during construction                                    |       | 4,065                                      |       | 4,305 |   |
| Interest  income                                                                        |       | 180                                        |       | 989 |   |
| Provision  for other income taxes                                                       |       | (79                                        | )          | (334 | ) |
| Other,  net                                                                             |       | (177                                       | )          | (789 | ) |
|                                                                                    |       | 3,989                                      |       | 4,171 |   |
| **Interest charges:**                                                                   |       |                                       |       |   |   |
| Long-term  debt                                                                         |       | 31,457                                     |       | 26,476 |   |
| Note  payable to securitization trust                                                   |       | 3,188                                      |       | 3,188 |   |
| Short-term  debt                                                                        |       | 981                                        |       | 1,085 |   |
| Allowance  for borrowed funds used during construction                                  |       | (6,214                                     | )          | (4,552 | ) |
| Other                                                                                   |       | (432                                       | )          | 891 |   |
|                                                                                    |       | 28,980                                     |       | 27,088 |   |
| ** **                                                                              |       |                                       |       |   |   |
| **Net income**                                                                          |       | $                                          | 33,368     |   | $ | 31,987 |   |
| Weighted  average number of common shares outstanding - basic                           |       | 34,369                                     |       | 33,777 |   |
| Weighted  average number of common shares outstanding - diluted                         |       | 34,396                                     |       | 33,806 |   |
| **Total earnings per weighted average share of  common stock – basic and diluted** | ** ** | **$**                                      | **0.97**   |   | $ | 0.95 |   |
| **Dividends per share of common stock**                                                 | ** ** | **$**                                      | **0.96**   |   | $ | 0.96 |   |

 

*See accompanying Notes to Consolidated Financial Statements.*

 

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**THEEMPIRE DISTRICT ELECTRIC COMPANY**

**CONSOLIDATEDSTATEMENTS OF OPERATIONS (UNAUDITED)**

 
| ** **                                                                              | ** ** | **Twelve Months Ended**                    | ** ** |
|-----------------------------------------------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                                                              | ** ** | **September 30,**                     | ** ** |
| ** **                                                                              | ** ** | **2009**                                   | ** ** | **2008** | ** ** |
| ** **                                                                              | ** ** | **(000’s except per share  amounts)** | ** ** |
| **Operating revenues:**                                                                 | ** ** | ** **                                 |       |   |   |
| Electric                                                                                |       | $                                          | 437,247    |   | $ | 434,978 |   |
| Gas                                                                                     |       | 63,759                                     |       | 60,687 |   |
| Water                                                                                   |       | 1,754                                      |       | 1,814 |   |
| Other                                                                                   |       | 4,791                                      |       | 4,204 |   |
|                                                                                    |       | 507,551                                    |       | 501,683 |   |
| **Operating revenue deductions:**                                                       |       |                                       |       |   |   |
| Fuel  and purchased power                                                               |       | 185,142                                    |       | 206,881 |   |
| Cost  of natural gas sold and transported                                               |       | 41,770                                     |       | 37,986 |   |
| Regulated  operating expenses                                                           |       | 72,384                                     |       | 72,374 |   |
| Other  operating expenses                                                               |       | 1,870                                      |       | 1,725 |   |
| Maintenance  and repairs                                                                |       | 33,904                                     |       | 27,821 |   |
| Gain  on sale of assets                                                                 |       | —                                     |       | (1,241 | ) |
| Depreciation  and amortization                                                          |       | 51,132                                     |       | 54,327 |   |
| Provision  for income taxes                                                             |       | 20,632                                     |       | 13,474 |   |
| Other  taxes                                                                            |       | 26,250                                     |       | 25,573 |   |
|                                                                                    |       | 433,084                                    |       | 438,920 |   |
|                                                                                    |       |                                       |       |   |   |
| **Operating income**                                                                    |       | 74,467                                     |       | 62,763 |   |
| **Other income and (deductions):**                                                      | ** ** | ** **                                 |       |   |   |
| Allowance  for equity funds used during construction                                    |       | 5,689                                      |       | 4,934 |   |
| Interest  income                                                                        |       | 248                                        |       | 1,062 |   |
| Benefit/(provision)  for other income taxes                                             |       | 257                                        |       | (384 | ) |
| Other,  net                                                                             |       | (957                                       | )          | (1,073 | ) |
|                                                                                    |       | 5,237                                      |       | 4,539 |   |
| **Interest charges:**                                                                   |       |                                       |       |   |   |
| Long-term  debt                                                                         |       | 41,023                                     |       | 34,533 |   |
| Note  payable to securitization trust                                                   |       | 4,250                                      |       | 4,250 |   |
| Short-term  debt                                                                        |       | 1,749                                      |       | 1,850 |   |
| Allowance  for borrowed funds used during construction                                  |       | (8,251                                     | )          | (6,056 | ) |
| Other                                                                                   |       | (171                                       | )          | 1,140 |   |
|                                                                                    |       | 38,600                                     |       | 35,717 |   |
| **Net income**                                                                          |       | 41,104                                     |       | 31,585 |   |
| Weighted  average number of common shares outstanding – basic                      |       | 34,264                                     |       | 33,123 |   |
| Weighted  average number of common shares outstanding – diluted                    |       | 34,288                                     |       | 33,152 |   |
| **Total earnings per weighted average share of  common stock – basic and diluted** | ** ** | **$**                                      | **1.20**   |   | $ | 0.95 |   |
| **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** | ** ** |
|------------------------------------------------------------------------------------------------------------------------|------------|------------------------|------------|
| ** **                                                                                                             | ** ** | **September 30,** | ** ** |
| ** **                                                                                                             | ** ** | **2009**               | ** ** | **2008** | ** ** |
| ** **                                                                                                             | ** ** | **($-000’s)**     | ** ** |
|                                                                                                                   | ** ** | ** **             |       |   |   |
| **Net income**                                                                                                         |       | $                      | 14,829     |   | $ | 20,180 |   |
| Reclassification  adjustments for (gain)/loss included in net income or reclassified to  regulatory asset or liability |       | 6,015                  |       | (3,678 | ) |
| Net  change in fair market value of derivative contracts for period                                                    |       | (90                    | )          | (34,111 | ) |
| Income  taxes                                                                                                          |       | (2,258                 | )          | 14,398 |   |
| ** **                                                                                                             |       |                   |       |   |   |
| **Comprehensive income**                                                                                               |       | $                      | 18,496     |   | $ | (3,211 | ) |

 
| ** **                                                                                                             | ** ** | **Nine Months Ended**  | ** ** |
|------------------------------------------------------------------------------------------------------------------------|------------|------------------------|------------|
| ** **                                                                                                             | ** ** | **September 30,** | ** ** |
| ** **                                                                                                             | ** ** | **2009**               | ** ** | **2008** | ** ** |
| ** **                                                                                                             | ** ** | **($-000’s)**     | ** ** |
|                                                                                                                   |       |                   |       |   |   |
| **Net income**                                                                                                         |       | $                      | 33,368     |   | $ | 31,987 |   |
| Reclassification  adjustments for (gain)/loss included in net income or reclassified to  regulatory asset or liability |       | 12,679                 |       | (6,251 | ) |
| Net  change in fair market value of derivative contracts for period                                                    |       | (7,557                 | )          | (282 | ) |
| Income  taxes                                                                                                          |       | (1,951                 | )          | 2,489 |   |
|                                                                                                                   |       |                   |       |   |   |
| **Comprehensive income**                                                                                               |       | $                      | 36,539     |   | $ | 27,943 |   |

 
| ** **                                                                                                             | ** ** | **Twelve Months Ended** |
|------------------------------------------------------------------------------------------------------------------------|------------|-------------------------|
| ** **                                                                                                             | ** ** | **September 30,**  |
| ** **                                                                                                             | ** ** | **2009**                | ** ** | **2008** | ** ** |
| ** **                                                                                                             | ** ** | **($-000’s)**      | ** ** |
|                                                                                                                   | ** ** | ** **              |   |   |   |
| **Net income**                                                                                                         |       | $                       | 41,104 |   | $ | 31,585 |   |
| Reclassification  adjustments for (gain)/loss included in net income or reclassified to  regulatory asset or liability |       | 15,058                  |   | (6,606 | ) |
| Net  change in fair market value of derivative contracts for period                                                    |       | (24,669                 | ) | 3,405 |   |
| Income  taxes                                                                                                          |       | 3,662                   |   | 1,220 |   |
| ** **                                                                                                             |       |                    |   |   |   |
| **Comprehensive income**                                                                                               |       | $                       | 35,155 |   | $ | 29,604 |   |

 

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

 

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**THE EMPIRE DISTRICT ELECTRIC COMPANY**

**CONSOLIDATEDBALANCE SHEETS (UNAUDITED)**

 
| ** **                                            | ** ** | **September 30, 2009** | ** ** | **December 31, 2008** | ** ** |
|-------------------------------------------------------|------------|-----------------------------|------------|----------------------------|------------|
| ** **                                            | ** ** | **($-000’s)**          | ** ** |
| **Assets**                                            |       |                        |       |                       |       |
| Plant and property, at original cost:                 |       |                        |       |                       |       |
| Electric                                              |       | $                           | 1,599,149  |                       | $          | 1,485,235 |   |
| Natural gas                                           |       | 57,662                      |       | 56,282                     |       |
| Water                                                 |       | 10,887                      |       | 10,560                     |       |
| Other                                                 |       | 29,147                      |       | 28,481                     |       |
| Construction work in progress                         |       | 293,213                     |       | 289,460                    |       |
|                                                  |       | 1,990,058                   |       | 1,870,018                  |       |
| Accumulated depreciation and amortization             |       | 559,889                     |       | 527,245                    |       |
|                                                  |       | 1,430,169                   |       | 1,342,773                  |       |
|                                                  | ** ** | ** **                  |       |                       |       |
| **Current assets:**                                   | ** ** | ** **                  |       |                       |       |
| Cash and cash equivalents                             |       | 5,908                       |       | 2,754                      |       |
| Accounts receivable – trade, net                 |       | 38,643                      |       | 39,487                     |       |
| Accrued unbilled revenues                             |       | 12,881                      |       | 25,170                     |       |
| Accounts receivable – other                      |       | 23,134                      |       | 19,353                     |       |
| Fuel, materials and supplies                          |       | 51,085                      |       | 54,202                     |       |
| Unrealized gain in fair value of derivative contracts |       | 3,907                       |       | 2,395                      |       |
| Prepaid expenses and other                            |       | 5,401                       |       | 5,675                      |       |
| Regulatory assets                                     |       | 1,137                       |       | 2,033                      |       |
|                                                  |       | 142,096                     |       | 151,069                    |       |
|                                                  | ** ** | ** **                  |       |                       |       |
| **Noncurrent assets and deferred  charges:**          | ** ** | ** **                  |       |                       |       |
| Regulatory assets                                     |       | 157,631                     |       | 162,026                    |       |
| Goodwill                                              |       | 39,492                      |       | 39,492                     |       |
| Unamortized debt issuance costs                       |       | 10,862                      |       | 9,133                      |       |
| Unrealized gain in fair value of derivative contracts |       | 3,493                       |       | 6,434                      |       |
| Other                                                 |       | 3,122                       |       | 2,919                      |       |
|                                                  |       | 214,600                     |       | 220,004                    |       |
| **Total Assets**                                      |       | $                           | 1,786,865  |                       | $          | 1,713,846 |   |

 

(Continued)

 

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

 

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**THE EMPIRE DISTRICT ELECTRIC COMPANY**

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

 
| ** **                                                                                         | ** ** | **September 30, 2009** | ** ** | **December 31, 2008** | ** ** |
|----------------------------------------------------------------------------------------------------|------------|-----------------------------|------------|----------------------------|------------|
| ** **                                                                                         | ** ** | **($-000’s)**          | ** ** |
| **Capitalization and Liabilities**                                                                 |       |                        |       |                       |       |
| Common stock, $1 par value, 35,885,915 and 33,981,579 shares  issued and outstanding, respectively |       | $                           | 35,886     |                       | $          | 33,982 |   |
| Capital in excess of par value                                                                     |       | 513,617                     |       | 483,443                    |       |
| Retained earnings                                                                                  |       | 13,879                      |       | 13,579                     |       |
| Accumulated other comprehensive income/(loss), net of  income tax                                  |       | 1,039                       |       | (2,132                     | )          |
| **Total common stockholders’  equity**                                                        |       | 564,421                     |       | 528,872                    |       |
|                                                                                               |       |                        |       |                       |       |
| **Long-term debt (net of current  portion):**                                                      |       |                        |       |                       |       |
| Note payable to securitization trust                                                               |       | 50,000                      |       | 50,000                     |       |
| Obligations under capital lease                                                                    |       | 167                         |       | 174                        |       |
| First mortgage bonds and secured debt                                                              |       | 338,971                     |       | 312,953                    |       |
| Unsecured debt                                                                                     |       | 247,984                     |       | 248,440                    |       |
| **Total long-term debt**                                                                           |       | 637,122                     |       | 611,567                    |       |
| **Total long-term debt and common  stockholders’ equity**                                     |       | 1,201,543                   |       | 1,140,439                  |       |
|                                                                                               | ** ** | ** **                  |       |                       |       |
| **Current liabilities:**                                                                           | ** ** | ** **                  |       |                       |       |
| Accounts payable and accrued liabilities                                                           |       | 57,073                      |       | 69,502                     |       |
| Current maturities of long-term debt                                                               |       | 70,546                      |       | 20,160                     |       |
| Short-term debt                                                                                    |       | 44,000                      |       | 102,000                    |       |
| Customer deposits                                                                                  |       | 10,083                      |       | 9,577                      |       |
| Interest accrued                                                                                   |       | 12,821                      |       | 5,921                      |       |
| Unrealized loss in fair value of derivative contracts                                              |       | 5,086                       |       | 12,276                     |       |
| Taxes accrued                                                                                      |       | 13,683                      |       | 3,174                      |       |
|                                                                                               |       | 213,292                     |       | 222,610                    |       |
| **Commitments and contingencies  (Note 7)**                                                        | ** ** | ** **                  |       |                       |       |
| **Noncurrent liabilities and  deferred credits:**                                                  | ** ** | ** **                  |       |                       |       |
| Regulatory liabilities                                                                             |       | 75,756                      |       | 66,585                     |       |
| Deferred income taxes                                                                              |       | 188,537                     |       | 173,511                    |       |
| Unamortized investment tax credits                                                                 |       | 2,485                       |       | 2,917                      |       |
| Pension and other postretirement benefit obligations                                               |       | 84,618                      |       | 83,151                     |       |
| Unrealized loss in fair value of derivative contracts                                              |       | —                      |       | 3,302                      |       |
| Other                                                                                              |       | 20,634                      |       | 21,331                     |       |
| ** **                                                                                         |       | 372,030                     |       | 350,797                    |       |
| **Total Capitalization and  Liabilities**                                                          |       | $                           | 1,786,865  |                       | $          | 1,713,846 |   |

 

*Seeaccompanying Notes to Consolidated Financial Statements.*

 

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**THEEMPIRE DISTRICT ELECTRIC COMPANY**

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

 
| ** **                                                                        | ** ** | **Nine Months Ended**  | ** ** |
|-----------------------------------------------------------------------------------|------------|------------------------|------------|
| ** **                                                                        | ** ** | **September 30,** | ** ** |
| ** **                                                                        | ** ** | **2009**               | ** ** | **2008** | ** ** |
| ** **                                                                        | ** ** | **($-000’s)**     | ** ** |
| **Operating activities:**                                                         | ** ** | ** **             |       |   |   |
| Net  income                                                                       |       | $                      | 33,368     |   | $ | 31,987 |   |
| **Adjustments to reconcile net income to cash  flows from operating activities**: |       |                   |       |   |   |
| Depreciation  and amortization                                                    |       | 46,115                 |       | 44,347 |   |
| Pension  and other postretirement benefit costs, net of contribution              |       | 2,447                  |       | 6,791 |   |
| Deferred  income taxes and unamortized investment tax credit, net                 |       | 11,605                 |       | 1,738 |   |
| Allowance  for equity funds used during construction                              |       | (4,065                 | )          | (4,305 | ) |
| Stock  compensation expense                                                       |       | 2,119                  |       | 2,095 |   |
| Non-cash  (gain)/loss on derivatives                                              |       | 9,495                  |       | (2,550 | ) |
| Gain  on sale of assets                                                           |       | (457                   | )          | — |   |
| **Cash flows impacted by changes in:**                                            |       |                   |       |   |   |
| Accounts  receivable and accrued unbilled revenues                                |       | 9,652                  |       | 9,930 |   |
| Fuel,  materials and supplies                                                     |       | 3,117                  |       | (9,479 | ) |
| Prepaid  expenses, other current assets and deferred charges                      |       | (6,634                 | )          | (4,839 | ) |
| Accounts  payable and accrued liabilities                                         |       | (18,915                | )          | (15,970 | ) |
| Customer  deposits, interest and taxes accrued                                    |       | 17,915                 |       | 23,999 |   |
| Other  liabilities and other deferred credits                                     |       | 1,095                  |       | 3,062 |   |
|                                                                              |       |                   |       |   |   |
| **Net cash provided by operating activities**                                     |       | 106,857                |       | 86,806 |   |
| ** **                                                                        | ** ** | ** **             |       |   |   |
| **Investing activities:**                                                         | ** ** | ** **             |       |   |   |
| Capital  expenditures – regulated                                            |       | (116,075               | )          | (162,062 | ) |
| Capital  expenditures and other investments – other                          |       | (978                   | )          | (1,537 | ) |
| Proceeds  from the sale of property, plant and equipment                          |       | 544                    |       | 1,538 |   |
|                                                                              |       |                   |       |   |   |
| **Net cash used in investing activities**                                         |       | (116,509               | )          | (162,061 | ) |
| ** **                                                                        |       |                   |       |   |   |
| **Financing activities:**                                                         |       |                   |       |   |   |
| Proceeds  from first mortgage bonds - electric                                    |       | 75,000                 |       | 89,950 |   |
| Long-term  debt issuance costs                                                    |       | (2,397                 | )          | (3,168 | ) |
| Proceeds  from issuance of common stock, net of issuance costs                    |       | 30,420                 |       | 4,413 |   |
| Net  short-term debt repayments                                                   |       | (58,000                | )          | 22,360 |   |
| Dividends                                                                         |       | (33,068                | )          | (32,433 | ) |
| Proceeds  from issuance of notes payable                                          |       | 1,431                  |       | — |   |
| Other                                                                             |       | (580                   | )          | (256 | ) |
| ** **                                                                        |       |                   |       |   |   |
| **Net cash provided by financing activities**                                     |       | 12,806                 |       | 80,866 |   |
| **Net increase in cash and cash equivalents**                                     |       | 3,154                  |       | 5,611 |   |
| **Cash and cash equivalents at beginning of period**                              |       | 2,754                  |       | 4,043 |   |
| **Cash and cash equivalents at end of period**                                    |       | $                      | 5,908      |   | $ | 9,654 |   |

 

*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 November 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**

 

InJune 2009, the FASB issued an accounting pronouncement amending “GenerallyAccepted Accounting Principles”. This pronouncement is effective for periodsending after September 15, 2009. The amendment identifies the sources ofaccounting principles, and establishes the FASB Accounting StandardsCodification (Codification) as the only source of authoritative accountingprinciples recognized by the FASB. This pronouncement is not intended to changegenerally accepted accounting principles. We adopted this pronouncement on September 15,2009. As a result of this adoption, the Financial Accounting Standardspreviously listed as FASBs have been replaced with the new standardsreferences. This change did not change the underlying principles and, therefore,had no effect on our financial statements.

 

Weadopted new accounting guidance on fair value measurements and disclosures on January 1,2008. This guidance defines fair value, establishes a framework for measuringfair value in generally accepted accounting principles and expands disclosuresabout fair value measurements. This guidance applies to other accountingpronouncements that require or permit fair value measurements. The guidancecontains a scope exception for leases and other accounting pronouncements thataddress fair value measurements for purposes of lease classification ormeasurement. The adoption of this guidance for financial assets and financialliabilities did not have a material impact on our consolidated financialposition, results of operations and cash flows. The guidance was amended todelay the effective date for all nonfinancial assets and nonfinancialliabilities to fiscal years beginning after November 15, 2008. We adoptedthis portion of the guidance on January 1, 2009. The adoption of theguidance for nonfinancial assets and nonfinancial liabilities did not have aneffect on our consolidated financial position, results of operations or cashflows. (See Note 5).

 

In April 2008, the FASBamended the guidance for derivatives and hedging to enhance the disclosureframework. We adopted this amendment on January 1, 2009. (See Note 4below).

 

InMay 2009, the FASB issued accounting guidance covering subsequent events.This guidance is effective for periods ending after June 15, 2009 andrequires 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 this guidance

 

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uponits issuance by the FASB. The adoption of this guidance did not have a materialeffect on our financial statement disclosures. (See Note 1 above).

 

InDecember 2008, the FASB amended thedefined benefit plans’ disclosure guidance. The amendment requiresadditional disclosures related to pension and other postretirement benefit planassets. The amendment will be effective as of December 31, 2009 andrequires disclosure of the fair value of each major category of plan asset of adefined benefit pension or postretirement plan. In addition, employers arerequired to disclose information enabling users to understand investment policiesand strategies, assess the inputs and valuation techniques used to develop fairvalue measurements, and to disclose any significant concentrations of riskswithin plan assets. We do not expect the adoption of this amendment to have amaterial effect on our results of operations, financial position or liquiditybecause it provides enhanced disclosure requirements only.

 

InApril 2009, the FASB amended the fair value measurements and disclosuresguidance to provide additional guidance for estimating fair value in accordancewith the fair value measurements guidance, when the volume and level ofactivity for an asset or liability has decreased significantly. This guidancealso addresses identifying circumstances that indicate a transaction is notorderly. The amendment was effective as of June 30, 2009. The adoption ofthe amendment did not have any effect on our results of operations, financialposition or liquidity.

 

InApril 2009, the FASB amended the debt and equity securities — subsequentmeasurement guidance to change the other-than-temporary impairment guidance inexisting Generally Accepted Accounting Principles (GAAP) for debt securities.The amendment provides for improved presentation and disclosure ofother-than-temporary impairments of debt securities in the financialstatements. This guidance was effective as of June 30, 2009. The adoptionof this amendment did not have a material effect on our results of operations,financial position or liquidity.

 

InApril 2009, the FASB amended the financial instruments disclosureguidance, to require disclosures about fair value of financial instruments ininterim financial statements, in addition to the annual financial statements asalready required by the accounting guidance. Adoption is required for interimperiods ending after June 15, 2009. As the amendment provides onlydisclosure requirements, the application of this standard did not have amaterial impact on our results of operations, financial position or liquidity.(See Note 5).

 

InJune 2009, the FASB amended the accounting guidance for transfers andservicing. This amendment is effective for annual periods beginning after November 15,2009. The amendment removes qualifying special-purpose entities (QSPE) fromGAAP. Additionally, the requirements for derecognizing financial assets havebeen changed, and additional disclosures about a transferor’s continuinginvolvement in transferred financial assets will be required. We do not expectthe adoption of this amendment to have a material effect on our financialstatements.

 

InJune 2009, the FASB amended the accounting guidance for consolidations.This amendment is effective for annual periods beginning after November 15,2009. The amendment requires an entity to complete a qualitative analysis whendetermining who must consolidate a variable interest entity. Additionally, theamendment requires additional disclosures, and an ongoing reassessment of whomust consolidate a variable interest entity. We are evaluating the impact ofthe adoption of this standard; however, we do not expect the adoption of thisstandard to have a material impact on our financial statements.

 

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.

 

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**Note 3— Regulatory Matters**

 

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

 

**Regulatory Assets and Liabilities**

 
| ** **                                                             | ** ** | **September 30, 2009** | ** ** | **December 31, 2008** | ** ** |
|------------------------------------------------------------------------|------------|-----------------------------|------------|----------------------------|------------|
| **Regulatory Assets:**                                                 |       |                        |       |                       |       |
| Unrecovered  purchased gas costs – gas segment, current           |       | $                           | 215        |                       | $          | 1,791 |   |
| Unrecovered  electric fuel and purchased power costs – current(1) |       | 922                         |       | 242                        |       |
| Regulatory  assets, current                                            |       | $                           | 1,137      |                       | $          | 2,033 |   |
| Pension  and other postretirement benefits(2)                          |       | 83,134                      |       | 84,926                     |       |
| Income  taxes                                                          |       | 37,379                      |       | 34,515                     |       |
| Storm  costs(3)                                                        |       | 12,601                      |       | 14,704                     |       |
| Unamortized  loss on reacquired debt                                   |       | 12,498                      |       | 13,490                     |       |
| Unamortized  loss on interest rate derivative                          |       | 2,169                       |       | 2,405                      |       |
| Asbury  five-year maintenance                                          |       | 1,514                       |       | 1,855                      |       |
| Deferred  Iatan construction accounting costs(4)                       |       | 1,715                       |       | —                     |       |
| Asset  retirement obligation                                           |       | 3,231                       |       | 3,118                      |       |
| Unrecovered  purchased gas costs – gas segment                    |       | 383                         |       | 3,787                      |       |
| Unsettled  derivative losses – electric segment                   |       | —                      |       | 1,218                      |       |
| Customer  programs                                                     |       | 1,056                       |       | 591                        |       |
| System  reliability – vegetation management                       |       | 1,080                       |       | 654                        |       |
| Other                                                                  |       | 871                         |       | 763                        |       |
| Regulatory  assets, long-term                                          |       | $                           | 157,631    |                       | $          | 162,026 |   |
| **Total**                                                              |       | $                           | 158,768    |                       | $          | 164,059 |   |

 
| ** **                                                 | ** ** | **September 30, 2009** | ** ** | **December 31, 2008** | ** ** |
|------------------------------------------------------------|------------|-----------------------------|------------|----------------------------|------------|
| **Regulatory Liabilities:**                                |       |                        |       |                       |       |
| Costs  of removal                                          |       | $                           | 51,336     |                       | $          | 43,713 |   |
| Income  taxes                                              |       | 11,118                      |       | 11,126                     |       |
| Unamortized  gain on interest rate derivative              |       | 4,094                       |       | 4,221                      |       |
| Pension  and other postretirement benefits(5)              |       | 6,414                       |       | 7,042                      |       |
| Over  recovered electric fuel and purchased power costs(6) |       | 1,111                       |       | 228                        |       |
| Other                                                      |       | 1,683                       |       | 255                        |       |
| **Total**                                                  |       | $                           | 75,756     |                       | $          | 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 $0.4 million in pension and other postretirement benefit costshave been recognized since January 1, 2009 to reflect the amortization ofthe regulatory assets that were recorded at the time of the acquisition of theAquila, Inc. gas properties.

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

(4) Includes$0.5 million of deferred depreciation costs and $1.2 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 below).

(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 $0.3 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.

 

OnApril 19, 2009, we began recording deferred carrying charges associatedwith our share of the environmental upgrades recently completed at our Iatan 1facility subsequent to the in-service date in accordance with our regulatoryplan. The effect of these deferred carrying charges is reflected in regulatedoperating expenses, depreciation and in other interest on the statement of operations.Construction accounting, for purposes of the regulatory plan, is specific toIatan 1 and Iatan 2 construction and allows us to defer certain charges asregulatory assets, including

 

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depreciationand carrying costs, related to operation of the facilities until the facilitiesare ultimately included in our rate base. The amounts deferred, which began atthe in-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.

 

Therehave been no changes to the rate base inclusions, expected recoverability oramortizable lives of our regulatory assets and liabilities since December 31,2008, other than the Iatan construction accounting carrying costs and windstorm costs discussed above.

** **

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

 

Wecurrently engage in hedging activities in an effort to minimize our risk fromvolatile natural gas prices. We enter into contracts with counterpartiesrelating to our future natural gas requirements that lock in prices (withrespect to a range of predetermined percentages of our expected future naturalgas needs) in an attempt to lessen the volatility in our fuel expense and gainpredictability. We recognize that if risk is not timely and adequately balancedor if counterparties fail to perform contractual obligations, actual resultscould differ materially from intended results.

 

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

 

Forinstruments entered into prior to September 1, 2008, we record unrealizedgains/(losses) on the ineffective portion of our gas hedging activities in “Fueland purchased power” under the operating revenue deductions section of ourStatement of Operations since all of our gas hedging activities are related tostabilizing fuel costs as part of our fuel procurement program and are notspeculative activities. Risks and uncertainties affecting the determination offair value include:  market conditions inthe energy industry, especially the effects of price volatility, regulatory andglobal political environments and requirements, fair value estimations onlonger term contracts, the effectiveness of the derivative instrument inhedging the change in fair value of the hedged item, estimating underlying fueldemand and counterparty ability to perform. If we estimate that we haveoverhedged forecasted demand, the gain or loss on the overhedged portion willbe recognized immediately as fuel and purchased power expense in ourConsolidated Statement of Operations.

 

Asof September 30, 2009 and December 31, 2008, we have recorded thefollowing assets and liabilities representing the fair value of derivativefinancial instruments, (in thousands):

 
| **ASSET DERIVATIVES**                               | ** ** | **September 30,**                   | ** ** | **December 31,** | ** **  |
|-----------------------------------------------------|------------|------------------------------------------|------------|-----------------------|-------------|
| **Derivatives  designated as hedging  instruments** | ** ** | **Balance Sheet Classification**         | ** ** | **2009  Fair Value**  | ** **  | **2008  Fair Value** | ** ** |
| Natural gas contracts, electric segment             |       | Current  assets                          |       | $                     |  3,032 |   | $ |  1,214 |   |
|                                                |       | Non-current  assets and deferred charges |       | 3,237                 |        | 6,208 |   |
|                                                     |            |                                          |            |                       |             |  |  |  |  |

 
| **Derivatives  not designated as hedging  instruments due to  regulatory accounting** | ** ** | ** **                               | ** ** | ** ** | ** **      | ** ** | ** ** |
|---------------------------------------------------------------------------------------|------------|------------------------------------------|------------|------------|-----------------|------------|------------|
| Natural gas contracts, gas segment                                                    |       | Current  assets                          |       | 875        |            | 1,177      |       |
|                                                                                  |       | Non-current  assets and deferred charges |       | —     |            | 226        |       |
|                                                                                  |       |                                     |       |       |            |       |       |
| Natural gas contracts, electric segment                                               |       | Current  assets                          |       | —     |            | 4          |       |
|                                                                                  |       | Non-current  assets and deferred charges |       | 256        |            | —     |       |
| **Total derivatives assets**                                                          | ** ** | ** **                               | ** ** | **$**      | ** 7,400** | ** ** | **$**      | ** 8,829** | ** ** |
|                                                                                       |            |                                          |            |            |                 |            |            |  |  |

 

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| **LIABILITY DERIVATIVES**                           | ** ** | **September 30,**                       | ** ** | **December 31,**      | ** **  |
|-----------------------------------------------------|------------|----------------------------------------------|------------|----------------------------|-------------|
| **Derivatives  designated as hedging  instruments** | ** ** | **Balance Sheet Classification**             | ** ** | **2009********Fair Value** | ** **  | **2008********Fair Value** | ** ** |
| Natural gas contracts, electric segment             |       | Current  liabilities                         |       | $                          |  4,591 |   | $ |  6,254 |   |
|                                                |       | Non-current liabilities and deferred credits |       | —                     |        | 3,282 |   |
|                                                     |            |                                              |            |                            |             |  |  |  |  |

 
| **Derivatives  not designated as hedging  instruments due to********regulatory accounting** | ** ** | ** **                                   | ** ** | ** ** | ** **      | ** ** | ** ** |
|---------------------------------------------------------------------------------------------|------------|----------------------------------------------|------------|------------|-----------------|------------|------------|
| Natural gas contracts, gas segment                                                          |       | Current  liabilities                         |       | $          |  495       |       | $          |  4,474 |   |
|                                                                                        |       | Non-current liabilities and deferred credits |       | —     |            | 20         |       |
| Natural gas contracts, electric segment                                                     |       | Current  liabilities                         |       | —     |            | 1,548      |       |
| **Total derivatives liabilities**                                                           | ** ** | ** **                                   | ** ** | **$**      | ** 5,086** | ** ** | **$**      | ** 15,578** | ** ** |

 

*Electric*

 

A$1.0 million net of tax, unrealized gain representing the fair market value ofour electric segment derivative contracts treated as cash flow hedges isrecognized as Accumulated Other Comprehensive Income in the capitalizationsection of the balance sheet as of September 30, 2009. The tax effect of$0.6 million on this gain is included in deferred taxes. These amounts will beadjusted cumulatively on a monthly basis during the determination periods,beginning October 1, 2009 and ending on September 30, 2011. At theend of each determination period, or if cash flow hedge treatment isdiscontinued, any realized gain or loss for that period related to theinstrument will be reclassified to fuel expense. As of September 30, 2009,approximately $1.6 million of unrealized losses are applicable to financialinstruments which will settle within the next twelve months.

 

EffectiveSeptember 1, 2008, in conjunction with the implementation of the Missourifuel adjustment clause in the July 2008 Missouri Public Service Commission(MPSC) rate order, the unrealized losses or gains from new cash flow hedges arerecorded in regulatory assets or liabilities. This is in accordance with theaccounting guidance for regulated activities, given that those regulatoryassets and liabilities are probable of recovery through our fuel adjustment mechanism.Unrealized gains and losses from cash flow hedges existing at September 1,2008 will continue to be recorded through comprehensive income. Once settled,the realized gain or loss will be recorded as fuel expense and be subject tothe fuel adjustment clause.

 

Thefollowing tables set forth the actual pre-tax gains/(losses) and the mark tomarket effect of unsettled positions from the qualified portion of our hedgingactivities for the electric segment for each of the periods ended September 30,(in thousands):

 
| **Derivatives in Cash  Flow Hedging**                | ** ** | **Statement  of  Operations ** | ** ** | **Amount  of Gain / (Loss) Reclassed from OCI into Income  (Effective portion)** | ** **       |
|------------------------------------------------------|------------|-------------------------------------|------------|----------------------------------------------------------------------------------|------------------|
| **Relationships -**                                  | ** ** | **Classification  of Gain /**       | ** ** | **Three  Months Ended**                                                          | ** **       | **Nine  Months Ended** | ** ** | **Twelve  Months Ended** | ** ** |
| **Electric Segment**                                 | ** ** | **(Loss)  on Derivative**           | ** ** | **2009**                                                                         | ** **       | **2008** | ** ** | **2009** | ** ** | **2008** | ** ** | **2009** | ** ** | **2008** | ** ** |
| Commodity  contracts                                 |       | Fuel and purchased power  expense   |       | $                                                                                |  (6,015     | ) | $ |  3,678 |   | $ |  (12,679 | ) | $ |  6,251 |   | $ |  (15,058 | ) | $ |  6,606 |   |
|                                                 |       |                                |       |                                                                             |             |   |   |   |   |   |   |   |   |   |   |
| **Total Effective –**** Electric Segment** | ** ** | ** **                          | ** ** | **$**                                                                            | ** (6,015** | **)** | **$** | ** 3,678** | ** ** | **$** | ** (12,679** | **)** | **$** | ** 6,251** | ** ** | **$** | ** (15,058** | **)** | **$** | ** 6,606** | ** ** |

 
| **Derivatives in Cash  Flow Hedging**                | ** ** | **Statement  of**                                             | ** ** | **Amount  of Gain / (Loss) Recognized in OCI on Derivative  (Effective portion)** | ** **    |
|------------------------------------------------------|------------|---------------------------------------------------------------|------------|-----------------------------------------------------------------------------------|---------------|
| **Relationships -**                                  | ** ** | **Comprehensive**                                             | ** ** | **Three  Months Ended**                                                           | ** **    | **Nine 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 |       | $                                                                                 |  (90     | ) | $ |  (34,111 | ) | $ |  (7,557 | ) | $ |  (282 | ) | $ |  (24,669 | ) | $ |  3,405 |   |
|                                                 |       |                                                          |       |                                                                              |          |   |   |   |   |   |   |   |   |   |   |
| **Total Effective –**** Electric Segment** | ** ** | ** **                                                    | ** ** | **$**                                                                             | ** (90** | **)** | **$** | ** (34,111** | **)** | **$** | ** (7,557** | **)** | **$** | ** (282** | **)** | **$** | ** (24,669** | **)** | **$** | ** 3,405** | ** ** |

 

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Thefollowing table sets forth “mark-to-market” pre-tax gains/(losses) from theineffective portion of our hedging activities for the electric segment for eachof the periods ended September 30, (in thousands):

 
| **Derivatives in 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**                                                                                                              | ** ** | **Nine Months Ended** | ** ** | **Twelve Months Ended** | ** ** |
| **Segment**                                          | ** ** | **Derivative**                                       | ** ** | **2009**                                                                                                                                      | ** ** | **2008** | ** ** | **2009** | ** ** | **2008** | ** ** | **2009** | ** ** | **2008** | ** ** |
| Commodity contracts                                  |       | Fuel  and purchased power expense                    |       | $                                                                                                                                             | —     |   | $ | (3 | ) | $ | — |   | $ | (271 | ) | $ | 1 |   | $ | 10 |   |
|                                                 |       |                                                 |       |                                                                                                                                          |       |   |   |   |   |   |   |   |   |   |   |
| **Total Ineffective —****Electric Segment**     | ** ** | ** **                                           | ** ** | **$**                                                                                                                                         | **—** | ** ** | **$** | **(3** | **)** | **$** | **—** | ** ** | **$** | **(271** | **)** | **$** | **1** | ** ** | **$** | **10** | ** ** |

 

Thefollowing tables set forth “mark-to-market” pre-tax gains/(losses) fromderivatives not designated as hedging instruments for the electric segment foreach of the periods ended September 30, (in thousands):

 
| **Derivatives Not  Designated as Hedging  Instruments - Due to** | ** ** | **Balance Sheet  Classification of** | ** ** | **Amount of Gain / (Loss) Recognized on Balance Sheet** | ** ** |
|------------------------------------------------------------------|------------|--------------------------------------|------------|---------------------------------------------------------|------------|
| **Regulatory Accounting**                                        | ** ** | **Gain / (Loss) on**                 | ** ** | **Three Months Ended**                        | ** ** | **Nine Months Ended** | ** ** | **Twelve Months Ended** | ** ** |
| **Electric Segment**                                             | ** ** | **Derivative**                       | ** ** | **2009**                                                | ** ** | **2008** | ** ** | **2009** | ** ** | **2008** | ** ** | **2009** | ** ** | **2008** | ** ** |
| Commodity contracts                                              |       | Regulatory  (assets)/liabilities     |       | $                                                       | 227        |   | $ | — |   | $ | (765 | ) | $ | — |   | $ | (2,309 | ) | $ | — |   |
|                                                             |       |                                 |       |                                                    |       |   |   |   |   |   |   |   |   |   |   |
| **Total Electric Segment**                                       | ** ** | ** **                           | ** ** | **$**                                                   | **227**    | ** ** | **$** | **—** | ** ** | **$** | **(765** | **)** | **$** | **—** | ** ** | **$** | **(2,309** | **)** | **$** | **—** | ** ** |

 
| **Derivatives Not  Designated as Hedging  Instruments Due to** | ** ** | **Statement of  Operations  Classification of** | ** ** | **Amount of Gain / (Loss) Recognized in Income on Derivative** | ** ** |
|----------------------------------------------------------------|------------|-------------------------------------------------|------------|----------------------------------------------------------------|------------|
| **Regulatory Accounting**                                      | ** ** | **Gain /  (Loss) on**                           | ** ** | **Three Months Ended**                               | ** ** | **Nine Months Ended** | ** ** | **Twelve Months Ended** | ** ** |
| **Electric Segment**                                           | ** ** | **Derivative**                                  | ** ** | **2009**                                                       | ** ** | **2008** | ** ** | **2009** | ** ** | **2008** | ** ** | **2009** | ** ** | **2008** | ** ** |
| Commodity contracts                                            |       | Fuel  and purchased power expense               |       | $                                                              | (1,053     | ) | $ | — |   | $ | (2,180 | ) | $ | 302 |   | $ | (2,509 | ) | $ | — |   |
|                                                           |       |                                            |       |                                                           |       |   |   |   |   |   |   |   |   |   |   |
| **Total Electric Segment**                                     | ** ** | ** **                                      | ** ** | **$**                                                          | **(1,053** | **)** | **$** | **—** | ** ** | **$** | **(2,180** | **)** | **$** | **302** | ** ** | **$** | **(2,509** | **)** | **$** | **—** | ** ** |

 

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

Asof October 30, 2009, 81% of our anticipated volume of natural gas usagefor our electric operations for the remainder of 2009 is hedged, either throughphysical (0.6 million Dths) or financial contracts (0.2 million Dths), at anaverage price of $6.748 per Dekatherm (Dth). In addition, the following volumesand percentages of our anticipated volume of natural gas usage for our electricoperations for the next four years are hedged at the following average pricesper Dth:

 
| **Year** | ** ** | **% Hedged** | ** ** | **Dth Hedged** | ** ** | **Average Price** | ** ** |
|----------|------------|-------------------|------------|---------------------|------------|------------------------|------------|
| 2010(1)  |       | 80                | %          | 7,225,000           |       | $                      | 6.317      |   |
| 2011(1)  |       | 71                | %          | 5,115,000           |       | $                      | 5.840      |   |
| 2012     |       | 40                | %          | 3,085,000           |       | $                      | 7.016      |   |
| 2013     |       | 17                | %          | 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.

 

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Weutilize the following procurement guidelines for our electric segment:  currentyear up to 100% of expected gas usage, first year minimum of 60%, second yearminimum of 40%, third year minimum of 20% and fourth year minimum of 10%,subject to a maximum of 80% of the expected gas usage in any one year.

 

OnFebruary 15, 2008, we unwound 992,000 Dth of physical gas contractsoriginally scheduled for delivery in July and August of 2010 and2011. This transaction resulted in a gain of approximately $1.3 million aftertax which was recorded as a reduction to fuel and purchased power expense inthe Statement of Operations for the nine and twelve months ended September 30,2008.

 

*Gas*

 

We attempt to mitigate our natural gas price riskfor our gas segment by a combination of (1) injecting natural gas intostorage during the off-heating season months, (2) purchasing physicalforward contracts and (3) purchasing financial derivative contracts. Wetarget to have 95% of our storage capacity full by November 1 for theupcoming winter heating season. As the winter progresses, gas is withdrawn fromstorage to serve our customers. As of October 30, 2009, we had 1.8 millionDths in storage on the three pipelines that serve our customers. Thisrepresents 92% of our storage capacity. We have an additional 1.2 million Dthshedged through financial derivative and physical contracts. Our long-term hedgestrategy is to mitigate price volatility for our customers by hedging a minimumof 50% of current year, up to 50% of second year and up to 20% of third yearexpected gas usage by the beginning of the Actual Cost Adjustment (ACA)year at September 1. A PurchasedGas Adjustment (PGA) clause is included in our rates for our gas segmentoperations, therefore, we mark to market any unrealized gains or losses and anyrealized gains or losses relating to financial derivative contracts to aregulatory asset or regulatory liability account on our balance sheet.

 

Thefollowing table sets forth “mark-to-market” pre-tax gains / (losses) fromderivatives not designated as hedging instruments for the gas segment for eachof the periods ended September 30, (in thousands).

 
| **Derivatives Not Designated  as Hedging Instruments Due** | ** ** | **Balance Sheet   Classification of** | ** ** | **Amount of Gain / (Loss) Recognized on Balance Sheet** | ** ** |
|------------------------------------------------------------|------------|---------------------------------------|------------|---------------------------------------------------------|------------|
| **to Regulatory Accounting -**                             | ** ** | **Gain /  (Loss) on**                 | ** ** | **Three Months Ended**                        | ** ** | **Nine Months Ended** | ** ** | **Twelve Months Ended** | ** ** |
| **Gas Segment**                                            | ** ** | **Derivative**                        | ** ** | **2009**                                                | ** ** | **2008** | ** ** | **2009** | ** ** | **2008** | ** ** | **2009** | ** ** | **2008** | ** ** |
| Commodity contracts                                        |       | Regulatory  (assets)/liabilities      |       | $                                                       | 592        |   | $ | (5,535 | ) | $ | (1,170 | ) | $ | (5,606 | ) | $ | (4,502 | ) | $ | (6,203 | ) |
|                                                       |       |                                  |       |                                                    |       |   |   |   |   |   |   |   |   |   |   |
| **Total - Gas Segment**                                    | ** ** | ** **                            | ** ** | **$**                                                   | **592**    | ** ** | **$** | **(5,535** | **)** | **$** | **(1,170** | **)** | **$** | **(5,606** | **)** | **$** | **(4,502** | **)** | **$** | **(6,203** | **)** |

 

*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 September 30, 2009 is $2.2 million for which we haveposted no collateral in the normal course of business. If thecredit-risk-related contingent features underlying these agreements weretriggered on September 30,2009, we would have been required to post $0.2 million of collateral with oneof our counterparties. On September 30, 2009, we had no collateral posted with this counterparty.

 

**Note 5—Fair Value Measurements**

 

Theaccounting guidance on fair value measurements establishes a three-tier fairvalue hierarchy, which prioritizes the inputs used in measuring fair value.These tiers include: (i) Level 1,

 

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definedas quoted prices in active markets for identical instruments; (ii) Level2, defined as inputs other than quoted prices in active markets that are eitherdirectly or indirectly observable; and (iii) Level 3, defined asunobservable inputs in which little or no market data exists, thereforerequiring an entity to develop its own assumptions. Our Level 2 fair valuemeasurements consist of both quoted price inputs and inputs provided by a thirdparty that are derived principally from or corroborated by observable marketdata by correlation. Our Level 3 fair value measurements consist of both quotedprice inputs and unobservable quoted inputs provided by a third party.

 

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

 

Thefollowing fair value hierarchy table presents information about our assetsmeasured at fair value using the market value approach on a recurring basis asof September 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)** | ** ** |
| ** **                           | ** ** | **September 30,  2009**                      | ** ** |
| Net  derivative assets/(liabilities) |       | $                                                 | 2,314      |                                                                                                | $          | (923 | ) | $ | — |   | $ | 3,237 |   |
|                                 |       |                                              |       |                                                                                                |       |   |   |   |   |
| ** **                           | ** ** | **December 31,  2008**                       | ** ** |
| Net  derivative assets/(liabilities) |       | $                                                 | (6,749     | )                                                                                                   | $          | (14,117 | ) | $ | 1,160 |   | $ | 6,208 |   |

 

Thefollowing tables present the net fair value on a recurring basis usingsignificant unobservable inputs (Level 3) during the periods ended September 30,2009 and 2008 (in thousands):

 

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

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

 

----

(1) Netderivatives at September 30, 2009 included derivative assets of $3.2million and no derivative liabilities.

 
| **($ 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                                            |       | (9,778                 | )          |
| Purchases,  issuances, and settlements                                       |       | —                 |       |
| Transfers  into and (out of) Level 3                                         |       | —                 |       |
| Ending  Balance, September 30, 2008                                     |       | $                      | 12,295     |   |
| Changes  in unrealized gains relating to assets still held at reporting date |       | $                      | (9,778     | ) |

 

----

(1) Netderivatives at September 30, 2008 included derivative assets of $12.3million and no derivative liabilities.

 

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**FairValue Measurements Using Significant Unobservable Inputs (Level 3) — Year toDate**

 
| **($ 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                                                     |       | (1,738                 | )          |
| Purchases,  issuances, and settlements                                                |       | —                 |       |
| Transfers  into and (out of) Level 3                                                  |       | (1,233                 | )          |
| Ending  Balance, September 30, 2009                                              |       | $                      | 3,237      |   |
| Changes  in unrealized gains/(losses) relating to assets still held at reporting date |       | $                      | (1,738     | ) |

 

----

(1) Netderivatives at September 30, 2009 included derivative assets of $3.2million and no 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                                            |       | 334                    |       |
| Purchases,  issuances, and settlements                                       |       | —                 |       |
| Transfers  into and (out of) Level 3                                         |       | —                 |       |
| Ending  Balance, September 30, 2008                                     |       | $                      | 12,295     |   |
| Changes  in unrealized gains relating to assets still held at reporting date |       | $                      | 334        |   |

 

----

(1) Netderivatives at September 30, 2008 included derivative assets of $12.3million and no derivative liabilities.

 

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

 
| **($ in 000’s)**                                                            | ** ** | **Net Derivatives****(1)** | ** ** |
|---------------------------------------------------------------------------------------|------------|----------------------------|------------|
| Beginning  Balance, September 30, 2008                                           |       | $                          | 12,295     |   |
| Total  gains or (losses) (realized/unrealized)                                        |       |                       |       |
| Included  in earnings (or changes in net assets)                                      |       | —                     |       |
| Included  in comprehensive income                                                     |       | (7,825                     | )          |
| Purchases,  issuances, and settlements                                                |       | —                     |       |
| Transfers  into and (out of) Level 3                                                  |       | (1,233                     | )          |
| Ending  Balance, September 30, 2009                                              |       | $                          | 3,237      |   |
| Changes  in unrealized gains/(losses) relating to assets still held at reporting date |       | $                          | (7,825     | ) |

 

----

(1) Netderivatives at September 30, 2009 included derivative assets of $3.2million and no derivative liabilities.

 
| **($ in 000’s)**                                                   | ** ** | **Net Derivatives****(1)** | ** ** |
|------------------------------------------------------------------------------|------------|----------------------------|------------|
| Beginning  Balance, September 30, 2007                                  |       | $                          | 16,613     |   |
| Total  gains or (losses) (realized/unrealized)                               |       |                       |       |
| Included  in earnings (or changes in net assets)                             |       | —                     |       |
| Included  in comprehensive income                                            |       | (4,318                     | )          |
| Purchases,  issuances, and settlements                                       |       | —                     |       |
| Transfers  into and (out of) Level 3                                         |       | —                     |       |
| Ending  Balance, September 30, 2008                                     |       | $                          | 12,295     |   |
| Changes  in unrealized gains relating to assets still held at reporting date |       | $                          | (4,318     | ) |

 

----

(1) Netderivatives at September 30, 2008 included derivative assets of $12.3million and no derivative liabilities.

 

*Long-Term Debt*

 

Thecarrying amount of our total debt exclusive of capital leases at September 30,2009, was $708 million compared to a fair market value of approximately $721million. These estimates were based on the quoted market prices for the same orsimilar issues or on the current rates offered to us for debt of the sameremaining maturities. The estimated fair market value may not represent theactual value that could have been realized as of September 30, 2009 orthat will be realizable in the future.

 

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**Note 6— Financing**

 

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 amount of up to $60 million from time to time through UBS, as salesagent. On October 22, 2009, we amended the agreement to increase theaggregate offering amount from $60 million to $120 million. We intend to usethe net proceeds from this equity distribution program to repay short-term debtand for general corporate purposes, including to fund our current constructionprogram. During the third quarter of 2009, we issued and sold 1,542,682 sharespursuant to this equity distribution program, at an average price per share of$18.09, resulting in proceeds to us of approximately $26.7 million (afterpayment of approximately $1.2 million in commissions to the sales agent).Through October 5, 2009, in the aggregate, we have issued and sold1,692,290 shares pursuant to the program, resulting in net proceeds to us ofapproximately $29.3 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% first mortgagebonds due April 1, 2024. The net proceeds (after payment of expenses) ofapproximately $72.6 million wereused to repay short-term debt incurred, in part, to fund our currentconstruction 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 discussed below. There were no borrowings under this agreement at September 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 80 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 $10.0 million asof November 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 September 30, 2009, we are in compliance with theseratios. This credit facility is also subject to cross-default if we default onin excess of $10 million in the aggregate on our other indebtedness. Thisarrangement does not serve to legally restrict the use of our cash in thenormal course of operations. There were $40.0 million of availabilitythereunder of outstanding borrowings under this agreement at September 30,2009 and an additional $4.0 million was used to back up our outstandingcommercial paper.

 

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**Note 7— Commitments and Contingencies**

 

Weare a party to various claims and legal proceedings arising out of the normalcourse of our business. Management regularly analyzes this information, and hasprovided accruals for any liabilities, in accordance with applicable accountingrules. In the opinion of management, it is not probable, given our defenses,that the ultimate outcome of these claims and lawsuits will have a materialadverse affect upon our financial condition, or results of operations or cashflows.

 

**Coal, Natural Gas and Transportation Contracts**

 

Wehave entered into long and short-term agreements to purchase coal and naturalgas for our energy supply and natural gas operations. Certain of these are firmphysical contracts and others are derivatives that are used to hedge futurepurchases. Under these contracts, the natural gas supplies are divided intofirm physical commitments and derivatives that are used to hedge futurepurchases. In the event that this gas cannot be used, the gas would remain instorage or be liquidated at market price. The firm physical gas andtransportation commitments are as follows (in millions):

 

Firmphysical gas and transportation contracts

 
| October 1, 2009 through September 30,  2010 |   | $    | 42.8   |   |
|-------------------------------------------------------|--------|------|--------|--------|
| October 1, 2010 through September 30,  2012 |   | 61.9 |   |
| October 1, 2012 through September 30,  2014 |   | 37.6 |   |
| October 1, 2014 and beyond                       |   | 51.3 |   |

 

Wehave coal supply agreements and transportation contracts in place to providefor the delivery of coal to the plants. Some of these contracts are subject tofuel and index price adjustments. These contracts are written with ForceMajeure clauses that enable us to reduce tonnages or cease shipments undercertain circumstances or events. These include mechanical or electricalmaintenance items, acts of God, war or insurrection, strikes, weather and otherdisrupting events. This reduces the risk we have for not taking the minimumrequirements of fuel under the contracts. Due to 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

 
| October 1, 2009 through September 30,  2010 |   | $    | 22.1   |   |
|-------------------------------------------------------|--------|------|--------|--------|
| October 1, 2010 through September 30,  2012 |   | 17.4 |   |
| October 1, 2012 through September 30,  2013 |   | 6.1  |   |

 

**Purchased Power**

 

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

 

Wehave contracted with Westar Energy for the purchase of capacity and energythrough May 31, 2010. Commitments under this contract total approximately$10.8 million through May 31, 2010.

 

Wealso have a long-term (30 year) agreement for the purchase of capacity from thePlum Point Energy Station, a new 665-megawatt, coal-fired generating facilitywhich is being built by Dynegy near Osceola, Arkansas. Construction began inthe spring of 2006 and Dynegy reports that substantial completion is scheduledfor July 2010. We have the option to purchase an undivided ownershipinterest in the 50 megawatts covered by the purchased power agreement in 2015. 

 

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Commitmentsunder this contract, excluding the purchase option, total approximately $48.0million through June 30, 2015. Due to the expected delays of Plum Pointand Iatan 2, we have arranged for sufficient alternative transmission andgenerating capacity to meet our expected needs for May 2010 through July 2010.The incremental costs associated with this alternative will not have a materialimpact on our earnings and will be subject to our fuel adjustment mechanism.

 

Wehave a 20-year purchased power agreement with Cloud County Windfarm, LLC, ownedby Horizon Wind Energy, Houston, Texas to purchase the energy generated at theapproximately 105-megawatt Phase 1 Meridian Way Wind Farm located in CloudCounty, Kansas commencing with the commercial operation date, which was December 15,2008. We also have a 20-year contract with Elk River Windfarm, LLC, owned byIBERDROLA RENEWABLES, Inc. (formerly known as PPM Energy), to purchase theenergy generated at the 150-megawatt Elk River Windfarm located in ButlerCounty, Kansas. Although these agreements are considered operating leases 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**

 

OnMarch 14, 2006, we entered into contracts to purchase an undividedinterest in 50 megawatts of the Plum Point Energy Station’s new 665-megawatt,coal-fired generating facility which is being built near Osceola, Arkansas.Dynegy reports that substantial completion is scheduled for July, 2010. Theestimated cost is approximately $88.0 million, excluding allowance for fundsused during construction (AFUDC). Our share of the Plum Point costs through September 30,2009 was $82.2 million.

 

On June 13, 2006, we announced we had entered into an agreementwith Kansas City Power & Light (KCP&L) to purchase an undividedownership interest in the coal-fired Iatan 2 generating facility. We will own12%, or approximately 100 megawatts, of the 850-megawatt unit. Early in thethird quarter of 2009, KCP&L announced its efforts to produce a cost andschedule reforecast primarily to address on-going productivity issues that werenegatively impacting the original schedule. KCP&L now reports that theanticipated in-service date for Iatan 2 is late summer of 2010. Based on a latesummer in-service date, we expect base rates reflecting our investment to be ineffect in late 2010 as we filed a request with the MPSC on October 29,2009, for an annual increase in base rates for our Missouri electric customersin the amount of $68.2 million, or 19.6%. This request is primarily to allow usto recover capital expenditures associated with environmental upgrades at Iatan1 and our investment in new generating units at Iatan 2 and the Plum PointGenerating Station. The Signatory Parties are currently in discussions aboutprocedures to be used in this case, including the timing of the considerationand rate recovery of our investments in the three generating facilities andother expenditures. We also filed a request with the Kansas CorporationCommission (KCC) on November 4, 2009 for an annual increase in base ratesfor our Kansas electric customers in the amount of $5.2 million, or 24.6%. Thisrequest is primarily to allow us to recover capital expenditures associatedwith environmental upgrades at Iatan 1 completed in 2009 and at our Asburyplant completed in 2008 and our investment in new generating units at Iatan 2,the Plum Point Generating Station and our Riverton 12 unit that went on line in2007. Our share of the Iatan 2 construction costs is still expected to be in arange of approximately $218 million to $230 million. Our share of the Iatan 2costs through September 30, 2009 was $177.1 million. As a requirement forthe air permit for Iatan 2, and to help meet requirements of the Clean AirInterstate Rule (CAIR), additional emission control equipment was requiredfor Iatan 1. Our share of the Iatan 1 environmental costs was $53.0 millionthrough September 30, 2009. KCP&L reported the equipment had metregulatory in-service criteria as of April 19, 2009 and it is currently inservice. All of these construction expenditures exclude AFUDC.

 

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

 

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operationsand maintenance costs, may occur that may materially affect the schedule, budget,cost and performance of these projects.

 

**Leases**

 

Asdiscussed above, on June 25, 2007, we entered into a 20-year purchasedpower agreement with Cloud County Windfarm, LLC, owned by Horizon Wind Energy,Houston, Texas. Pursuant to the terms of the agreement, we will purchase all ofthe output from the approximately 105-megawatt Phase 1 Meridian Way Wind Farmlocated in Cloud County, Kansas. We do not own any portion of the windfarm.Annual payments are contingent upon output of the facility and can range fromzero to a maximum of approximately $14.6 million based on a 20-year averagecost.

 

OnDecember 10, 2004, we entered into a 20-year contract with Elk RiverWindfarm, LLC to purchase the energy generated at the 150-megawatt Elk RiverWindfarm located in Butler County, Kansas. We do not own any portion of thewindfarm. Payments for wind energy from the Elk River Windfarm are contingentupon output of the facility. Annual payments can run from zero to a maximum ofapproximately $16.9 million based on a 20-year average cost.

 

Paymentsfor these agreements are recorded as purchased power expenses, and, because ofthe contingent nature of these payments, are not included in operating leaseobligations.

 

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

 

During the third quarter, weentered into two railcar leases. The first operating lease is for 135 railcarsfor our Asbury plant for ten years with payments totaling $6.5 million. Thesecond operating lease is for 54 railcars which are still being constructed.This is a 15 year lease for our Plum Point plant and payments will bedetermined upon completion of the railcars in the fourth quarter of 2009.

 

**Environmental Matters**

 

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

 

***Electric Segment***

 

*Air.*

 

The1990 Amendments to the Clean Air Act, referred to as the 1990 Amendments,affect the Asbury, Riverton, State Line and Iatan 1 Power Plants and Units 3and 4 (the FT8 peaking units) at the Empire Energy Center. The 1990 Amendmentsrequire affected plants to meet certain emission standards, including maximumemission levels for sulfur dioxide (SO2) and nitrogen oxides (NOx).

 

SO2Emissions.

 

Underthe 1990 Amendments, the amount of SO2 an affected unit can emit is regulated.Each existing 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 the numberof tons of SO2 emitted during a given year by each of their affected units. Theannual reconciliation of allowances, which occurs on a facility wide basis, isheld each March 1 for the previous calendar year. The Environmental****Protection Agency****(EPA) withholds annually a percentage of theemission allowances allocated to each affected unit and sells those emissionallowances through a direct auction. We receive compensation from the EPA forthe sale of these withheld allowances. During 2008 and 2009, we received lessthan $0.1 million from the EPA auction.

 

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OurAsbury, Riverton and Iatan coal plants collectively receive 11,723 allowancesper year. They burn low sulfur Western coal (Powder River Basin), higher sulfurblend coal and/or petroleum coke. In addition, tire-derived fuel (TDF) is usedas a supplemental fuel at the Asbury Plant. The Riverton Plant can also burnnatural gas as its primary fuel. The State Line Plant, the Energy Center Units3 and 4 and Riverton Unit 12 are gas-fired facilities and are allocated zeroSO2 allowances. Annual allowance requirements for the State Line Plant, theEnergy Center Units 3 and 4 and Riverton Unit 12, which are not expected toexceed 20 allowances per year, will be transferred from our inventoried bank ofallowances. In 2008, the combined actual SO2 allowance need for all affectedplant facilities exceeded the number of allowances allocated to us by the EPA.As of March 1, 2009, we had 17,394 banked SO2 allowances as compared to23,800 at March 1, 2008. We project that our 2009 emissions will againexceed the number of allowances allocated by the EPA by an amount approximatelyequal to the difference during 2008.

 

Whenour SO2 allowance bank is exhausted, currently estimated to be mid-2011, wewill need to purchase additional SO2 allowances or build a Flue GasDesulphurization (FGD) scrubber system at our Asbury Plant. Based on currentand projected SO2 allowance prices and high-level estimated FGD scrubberconstruction costs ($81 million in 2010 dollars), we project it will be moreeconomical for us to purchase SO2 allowances than to build a scrubber at theAsbury Plant. Based on SO2 allowance market prices as of May 4, 2009 inconjunction with currently estimated future operating parameters at the AsburyPlant, we estimate it will cost us approximately $0.5 million to purchase SO2allowances for the remainder of 2011 and a range of approximately $0.6 millionto $0.9 million annually for the years 2012 through 2018. We would expect thecosts of SO2 allowances to be fully recoverable in our rates.

 

EffectiveMarch 1, 2005, the MPSC approved a Stipulation and Agreement granting usauthority to manage our SO2 allowance inventory in accordance with our SO2Allowance Management Policy (SAMP). The SAMP allows us to exchange bankedallowances for future vintage allowances and/or monetary value and, in extrememarket conditions, to sell SO2 allowances outright for monetary value. We havenot yet exchanged or sold any allowances under the SAMP.

 

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

 

NOxEmissions.

 

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

 

InMarch 2008, the EPA lowered the National Ambient Air Quality Standard(NAAQS) for ozone from 84 ppb to 75 ppb. Ozone, also called ground level smog,is formed by the mixing of NOx and****Volatile Organic Compounds (VOCs) in the presence ofsunlight. On September 16, 2009, the EPA announced it would reconsider the2008 Ozone NAAQS and that a proposed revision would be published by December 2009.It is our understanding that the EPA will propose to stay the requirement formeeting the March 2008 NAAQS of 75 ppb.

 

NOxemissions are further regulated as described in the Clean Air Interstate Rule sectionbelow.

 

Clean Air Interstate Rule (CAIR)

 

TheEPA issued its final CAIR on March 10, 2005. CAIR governed NOx and SO2emissions from fossil fueled units greater than 25 megawatts in 28 states,including Missouri, where our Asbury, Energy Center, State Line and Iatan UnitsNo. 1 and No. 2 are located and Arkansas where the Plum Point EnergyStation is being constructed. Kansas was not included in CAIR and our RivertonPlant was not affected.

 

OnJuly 11, 2008, the U.S. Court of Appeals for the District of Columbia Circuitvacated the CAIR Rule and remanded it back to the EPA. However, the courtstayed its vacatur on December 23, 2008. As a result, CAIR became effective forNOx on January 1, 2009 and will become effective for SO2 on January 1,2010.

 

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The CAIR is not directed to specific generationunits, but instead, requires the states (including Missouri and Arkansas) todevelop SIPs to comply with specific NOx and SO2 state-wide annual budgets.Missouri and Arkansas finalized their respective regulations and submittedtheir SIPs to the EPA, which were approved. We have received our full allotmentof allowances as published in the Missouri CAIR Rule. In addition to thisallotment, the Missouri Department of Natural Resources (MDNR) has allocated 61annual NOx allowances for 2009 to our account from the Renewable Energy Pooland we estimate we will be allocated an additional 663 annual NOx allowancesfor 2009 from the Compliance Supplemental Pool in 2010. Under the Arkansas CAIRrule, we will not receive allowances until approximately six years after PlumPoint Unit 1 is operational. In the interim, we will transfer allowances fromour Missouri units. Based on SIPs for Missouri and Arkansas, we believe we willhave excess annual and ozone season NOx allowances. SO2 allowances must beutilized at a 2:1 ratio for our Missouri units as compared to our non-CAIRKansas units beginning in 2010. As a result, based on current SO2 allowanceusage projections, we expect to exhaust our banked allowances by mid-2011 andwill need to purchase additional SO2 allowances or build a scrubber at ourAsbury Plant.

 

In order to meet CAIR requirements for Iatan 1and to meet air permit requirements for Iatan 2, pollution control equipmenthas been installed on Iatan 1. Installation was completed in April 2009and KCP&L reported the equipment met in-service criteria as of April 19,2009. This equipment includes a Selective Catalytic Reduction (SCR) system, anFGD scrubber and a baghouse, with our share of the capital cost estimated to bebetween $58 million and $60 million, excluding AFUDC. Of this amount,approximately $3.9 million was incurred in 2006, $12.1 million in 2007 and$27.3 million in 2008 with estimated expenditures of approximately $15.6million in 2009 (of which $9.7 million has been incurred through September 30,2009). KCP&L is in the process of closing out the project and expects finalcosts by the end of the year. This project was also included as part of ourExperimental Regulatory Plan approved by the MPSC.

 

Alsoto meet CAIR requirements, we constructed an SCR at Asbury that was completedin November 2007 and placed in service in February 2008 at a totalcost of approximately $31.0 million (excluding AFUDC). This project was alsoincluded as part of our Experimental Regulatory Plan approved by the MPSC andits cost is now reflected in base rates in Missouri.

 

TheEPA has announced that proposed revisions to CAIR will be published in May 2010with the final regulations expected in early 2011. On March 26, 2009, theEPA issued a letter to utilities cautioning about the uncertainty of future NOxallowance allocations.

 

AirPermits.

 

UnderTitle V of the 1990 Amendments, we must obtain site operating permits for eachof our plants from the authorities in the state in which the plant is located.These permits, which are valid for five years, regulate the plant site’s totalair emissions; including emissions from stacks, individual pieces of equipment,road dust, coal dust and other emissions. We have been issued permits forAsbury, Iatan, Riverton, State Line and the Energy Center Plants. We submittedthe required renewal applications for the State Line and Energy Center Title Vpermits in 2003 and the Asbury Title V permit in 2004 and will operate underthe existing permits until the MDNR issues the renewed permits. A ComplianceAssurance Monitoring (CAM) plan for particulate matter (PM) will be required bythe renewed permit for Asbury. We estimate that the capital costs associatedwith the PM CAM plan will not exceed $2 million. We submitted the renewalapplication for the Riverton Title V permit in June 2008 and the renewedpermit was issued August 27, 2009. A CAM plan for PM is required by therenewed permit for Riverton. No additional capital costs are anticipated.`

 

Anew air permit was issued for the Iatan Generating Station on January 31,2006. The new permit covers the entire Iatan Generating Station and includesthe existing Unit No. 1 and Iatan Unit No. 2 currently underconstruction. The Unit No. 1 SCR, scrubber and baghouse are fullyoperational and the unit is operating in compliance with the permit conditions.

 

TheClean Air Act requires companies to obtain permits and, if necessary, installcontrol equipment to reduce emissions when making a major modification or achange in operation if either is expected to cause a significant net increasein regulated emissions. The Sierra Club and Concerned Citizens of Platte Countyhave claimed that modifications were made to Iatan 1 prior to 

 

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theComprehensive Energy Plan project in violation of Clean Air Act regulations. Weown 12% of Iatan 1. As operator, KCP&L entered into a CollaborationAgreement with those parties that provide, among other things, for the releaseof such claims. In May 2008, a grand jury subpoena requesting documentswas received by KCP&L. KCP&L completed documentation delivery inresponse to the subpoena in March 2009. We were informed in September 2009 by KCP&L that the Departmentof Justice did not expect to bring criminal charges under the Clean Air Act inconnection with repair work, maintenance or modifications at Iatan Unit No.1.

 

CleanAir Mercury Rule (CAMR)

 

OnMarch 15, 2005, the EPA issued the CAMR regulations for mercury emissionsby power plants under the requirements of the 1990 Amendments to the Clean AirAct. The new mercury emission limits of CAMR Phase 1 were to go into effect January 1,2010. On February 8, 2008, the U.S. Court of Appeals for the District ofColumbia vacated the EPA’s CAMR regulations which was appealed to the U.S.Supreme Court on October 17, 2008. On February 23, 2009, the U.S.Supreme Court denied the appeal.

 

TheEPA has not issued guidance to the states regarding the vacated regulation norrecommended future actions. Based on CAMR, we installed a mercury analyzer atAsbury during late 2007 and installed two mercury analyzers at Riverton in 2008in order to verify our mercury emissions and to meet the monitoring compliancedate of January 1, 2009 and the Phase 1 mercury emission compliance dateof January 1, 2010. We operate the mercury analyzers at Riverton andAsbury in accordance with the appropriate state environmental regulator’sguidance.

 

TheCAMR rulemaking was revoked by the EPA after final adjudication. As a result,Maximum Achievable Control Technology (MACT) re-emerged under current law butno specific MACT rulemakings have yet been adopted in Missouri or Kansas. Todate, the EPA has not issued any new proposed rulemaking.

 

CO2 Emissions

 

Our coal and gas plants, vehicles and other facilities,including EDG (our gas segment), emit carbon dioxide (CO2) and/or othergreenhouse gases (GHG) which are measured in Carbon Dioxide Equivalents (CO2e).Although not currently regulated, increasing public concerns and politicalpressures from local, regional, national and international bodies are likely toresult in the passage of new laws mandating limits on GHG emissions. On September 22,2009, the EPA issued the Final Mandatory Reporting of Greenhouse Gases Rule whichrequires power generating and certain other facilities, including EDG, thatequal or exceed an emission threshold of 25,000 metric tons of CO2e to reportGHGs to the EPA annually. The first record keeping year is 2010 with initialreporting due in March 2011. In addition, on September 30, 2009, theEPA issued the proposed “Prevention of Significant Deterioration and Title VGreenhouse Gases Tailoring Rule” that would regulate GHG emissions fromemitting sources that equal or exceed a threshold of 25,000 short tons of CO2eannually. The EPA proposes to issue the final regulation in March 2010.The EPA indicated that Title V operating permits be the vehicle for regulationfor existing facilities with appropriate language inserted into the permits atrenewal. New units and major modifications to existing units would be regulatedunder the current Prevention of Significant Deterioration provisions of theClean Air Act. On June 26, 2009, the U.S. House of Representatives passedthe American Clean Energy and Security Act of 2009 (also known as H.R. 2454).The bill includes provisions to cap CO2e levels emitted byelectric utilities at 3% below 2005 levels beginning in 2012, and requiringpower generators to provide a specified amount of electricity using renewableenergy. Similar legislation is under consideration in the U.S. Senate. It isunclear at this time what effect, if any, final legislation will have on theEPA’s ability to regulate GHG emissions from stationary sources. We are closely monitoring proposed CO2elegislation. Certain states have taken steps to develop similar regulatory systemswhich may be more stringent than any federal regulations. For example, Kansasis a participating member of the Midwestern Greenhouse Gas Reduction Accord(MGGRA), one purpose of which is to develop a market-based cap and trademechanism to reduce GHG emissions. The MGGRA has announced, however, that itwill not issue a CO2e regulatory 

 

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system pending federal legislation development.Although there can be no guarantee and the ultimate cost of any GHG regulationscannot be determined at this time, we would expect the cost of complying withany such regulations to be fully recoverable in our rates. We also cannotpredict with certainty the impact to our financial position, liquidity orresults of operations at this time.

 

*Water.*

 

Weoperate under the Kansas and Missouri Water Pollution Plans that wereimplemented in response to the Federal Water Pollution Control Act Amendmentsof 1972. The Asbury, Iatan, Riverton, Energy Center and State Line plants arein compliance with applicable regulations and have received discharge permitsand subsequent renewals as required.

 

TheRiverton Plant is affected by final regulations for Cooling Water IntakeStructures issued under the Clean Water Act (CWA) Section 316(b) PhaseII. The regulations became final on February 16, 2004 and required thesubmission of a Sampling Report and Comprehensive Demonstration Study with thepermit renewal in 2008. Sampling and summary reports, which were completedduring the first quarter of 2008 and submitted to the KDHE, indicate that theeffect of the cooling water intake structure on Empire Lake’s aquatic life isinsignificant. The need for a further Demonstration Study is not expected. On January 25,2007, the United States Court of Appeals for the Second Circuit remanded keysections of these CWA regulations. On July 9,2007, the EPA suspended the regulation and is expected to revise and re-proposethe regulation by mid-2010. In addition, on April 14, 2008 certiorari wasgranted by the United States Supreme Court limited to the review as to whether Section 316(b) ofthe CWA authorized the EPA to compare costs with benefits in determining thebest technology available for minimizing adverse environmental impacts atcooling water intake structures. On April 1, 2009, the U.S. Supreme Courtoverturned the lower court’s ruling on the cost/benefit issue and remanded theregulation to the EPA. The permit renewal application was prepared andsubmitted in June 2008 and the final permit was received on January 1,2009. Under the initial regulations, we did not expect costs associated withcompliance to be material. We will reassess costs after the revised rules arecomplete.

 

*AshPonds.*

 

Weown and maintain coal ash ponds located at our Riverton and Asbury PowerPlants. Additionally, we own a 12 percent interest in a coal ash pond at theIatan Generating Station. 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 existing state and federal regulations. The EPA hasannounced its intention, by the end of 2009, to propose new regulationspursuant to the Resource Conservation and Recovery Act governing the managementand storage of coal ash wastes, and to determine whether to designate coal ashas a non-hazardous solid waste or as a hazardous waste. Following a major spillof coal ash from a surface impoundment at a coal burning power plant inTennessee in December 2008, there is mounting pressure on the EPA toregulate coal ash as a hazardous waste. If the EPA does so, coal ash wouldbecome subject to a variety of hazardous waste regulations and the cost ofhandling, transporting, storing and disposing of the material would increase. We cannot predict with certainty the impact ofany final EPA regulations on ourfinancial position, liquidity or results of operations at this time.

 

*RenewableEnergy.*

 

OnNovember 4, 2008, Missouri voters approved the Clean Energy Initiative(Proposition C). This initiative requires investor-owned utilities in Missouri(such as Empire) to generate or purchase electricity from renewable energysources, such as solar, wind, biomass and hydro power, at the rate of at least2% in retail sales by 2011, increasing to at least 15% by 2021. Kansas HouseBill 2369, enacted in May 2009, established a renewables portfoliostandard (RPS) for Kansas. The KCC will establish rules and regulations toadminister the portfolio standard within 12 months. At least 25 other stateshave adopted RPS programs that mandate some form of renewable generation. Someof these RPS programs incorporate a trading system in which utilities areallowed 

 

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tobuy and sell renewable energy certificates (RECs) in order to meet compliance.Additionally, RECs are utilized by many companies in “green” marketing efforts.REC prices are driven by various market forces. We have been selling RECs andplan to continue to sell all or a portion of the RECs associated with ourcontracts with Elk River Windfarm, LLC and Cloud County Windfarm, LLC. Withrespect to the energy underlying the RECs that we sell, we may not claim thatwe are purchasing renewable energy****for any purpose, including for purposes of complyingwith the new Missouri requirements. Over time, we expect to retain some of therenewable attributes associated with these contracts in order to meet the newMissouri requirements. Revenues from REC sales for the twelve months ended September 30,2009 and 2008 were $1.1 million and $1.8 million, respectively. Revenues fromREC sales for the nine months ended September 30, 2009 and 2008 were $0.9million and $1.6 million, respectively and for the quarter ended September 30,2009 and 2008 were $0.2 million and $0.5 million, respectively.

 

***Gas Segment***

 

The acquisition of our natural gas distributionassets in June 2006 involved the potential future remediation of twoformer manufactured gas plant (MGP) sites. Site #1 in Chillicothe, Missouri islisted in the MDNR Registry of Confirmed Abandoned or Uncontrolled HazardousWaste Disposal Sites in Missouri. Site #2 in Marshall, Missouri has received aletter of no further action from the MDNR. A Change of Use request and workplan was approved by the MDNR allowing us to expand our existing service centerat Site #1 in Chillicothe, Missouri. This project, which was completed in October 2007,included the removal of all excavated soil and the addition of a new concretesurface replacing the existing gravel at a cost of approximately $0.1 million.We estimate further remediation costs at these two sites to be no more thanapproximately $0.2 million, based on our best estimate at this time. Theremaining liability balance of $0.2 million is recorded under noncurrentliabilities and deferred credits. In our agreement with the MPSC approving theacquisition, it was agreed that we could reflect a liability and offsettingregulatory asset not to exceed $260,000 for the sites. The MPSC agreed that upto $260,000 of costs related to the clean up of these MGP sites would beallowed for future rate recovery. Accordingly, we concluded that rate recoverywas probable and at the acquisition date, a regulatory asset of $260,000 wasrecorded as part of the purchase price allocation based on our agreement withthe MPSC.

 

**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 September 30,** | ** ** |
|--------------------------------------------|------------|-------------------------------------------|------------|
| ** **                                 | ** ** | **Pension Benefits**                      | ** ** | **SERP** | ** ** | **OPEB** | ** ** |
| ** **                                 | ** ** | **2009**                                  | ** ** | **2008** | ** ** | **2009** | ** ** | **2008** | ** ** | **2009** | ** ** | **2008** | ** ** |
| Service cost                               |       | $                                         | 1,449      |   | $ | 952 |   | $ | 15 |   | $ | 19 |   | $ | 409 |   | $ | 424 |   |
| Interest cost                              |       | 2,478                                     |       | 2,295 |   | 37 |   | 39 |   | 879 |   | 892 |   |
| Expected return on plan assets             |       | (2,582                                    | )          | (2,688 | ) | — |   | — |   | (952 | ) | (937 | ) |
| Amortization of prior service cost **(1)** |       | 151                                       |       | 186 |   | (2 | ) | (2 | ) | (253 | ) | (253 | ) |
| Amortization of net actuarial loss **(1)** |       | 795                                       |       | 462 |   | 26 |   | 38 |   | 64 |   | 105 |   |
| **Net periodic benefit cost**              | ** ** | **$**                                     | **2,291**  | ** ** | **$** | **1,207** | ** ** | **$** | **76** | ** ** | **$** | **94** | ** ** | **$** | **147** | ** ** | **$** | **231** | ** ** |

 
| ** **                                 | ** ** | **Nine months ended September 30,** | ** ** |
|--------------------------------------------|------------|-------------------------------------|------------|
| ** **                                 | ** ** | **Pension Benefits**                | ** ** | **SERP** | ** ** | **OPEB** | ** ** |
| ** **                                 | ** ** | **2009**                            | ** ** | **2008** | ** ** | **2009** | ** ** | **2008** | ** ** | **2009** | ** ** | **2008** | ** ** |
| Service cost                               |       | $                                   | 3,459      |   | $ | 2,676 |   | $ | 46 |   | $ | 43 |   | $ | 1,372 |   | $ | 1,238 |   |
| Interest cost                              |       | 7,407                               |       | 6,786 |   | 111 |   | 102 |   | 2,930 |   | 2,712 |   |
| Expected return on plan assets             |       | (7,785                              | )          | (8,047 | ) | — |   | — |   | (2,882 | ) | (2,813 | ) |
| Amortization of prior service cost **(1)** |       | 453                                 |       | 558 |   | (6 | ) | (6 | ) | (758 | ) | (758 | ) |
| Amortization of net actuarial loss **(1)** |       | 2,387                               |       | 1,270 |   | 77 |   | 99 |   | 652 |   | 384 |   |
| **Net periodic benefit cost**              | ** ** | **$**                               | **5,921**  | ** ** | **$** | **3,243** | ** ** | **$** | **228** | ** ** | **$** | **238** | ** ** | **$** | **1,314** | ** ** | **$** | **763** | ** ** |

 

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| ** **                                 | ** ** | **Twelve months ended September 30,** | ** ** |
|--------------------------------------------|------------|---------------------------------------|------------|
| ** **                                 | ** ** | **Pension Benefits**                  | ** ** | **SERP** | ** ** | **OPEB** | ** ** |
| ** **                                 | ** ** | **2009**                              | ** ** | **2008** | ** ** | **2009** | ** ** | **2008** | ** ** | **2009** | ** ** | **2008** | ** ** |
| Service cost                               |       | $                                     | 4,351      |   | $ | 3,549 |   | $ | 60 |   | $ | 55 |   | $ | 1,785 |   | $ | 1,664 |   |
| Interest cost                              |       | 9,669                                 |       | 8,900 |   | 145 |   | 132 |   | 3,835 |   | 3,567 |   |
| Expected return on plan assets             |       | (10,467                               | )          | (10,617 | ) | — |   | — |   | (3,820 | ) | (3,877 | ) |
| Amortization of prior service cost **(1)** |       | 639                                   |       | 801 |   | (8 | ) | (9 | ) | (1,011 | ) | (1,011 | ) |
| Amortization of net actuarial loss **(1)** |       | 2,810                                 |       | 1,920 |   | 110 |   | 136 |   | 780 |   | 671 |   |
| **Net periodic benefit cost**              | ** ** | **$**                                 | **7,002**  | ** ** | **$** | **4,553** | ** ** | **$** | **307** | ** ** | **$** | **314** | ** ** | **$** | **1,569** | ** ** | **$** | **1,014** | ** ** |

 

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(1) Amounts are amortized from our regulatory asset originallyrecorded upon recognizing our net pension liability on the balance sheet.

 

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 in 2008.

 

On September 14, 2009,we made a $2.5 million contribution to our pension plan related to the 2008 planyear. No other contribution will be required in 2009. In 2009 we used ourpension funding credit to meet our funding obligations. However, in 2010 ourcontributions are estimated to be between $9.0 million and $15.0 million. Theactual minimum funding requirements will be determined based on the results ofthe actuarial valuations and the performance of our pension assets during 2009.

 

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

 

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

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

 
| ** **                 | ** ** | **Three Months Ended** | ** ** | **Nine Months Ended** | ** ** | **Twelve Months Ended** | ** ** |
|----------------------------|------------|------------------------|------------|-----------------------|------------|-------------------------|------------|
| ** **                 | ** ** | **2009**               | ** ** | **2008**              | ** ** | **2009**                | ** ** | **2008** | ** ** | **2009** | ** ** | **2008** | ** ** |
| **Compensation Expense**   |       | $                      | 589        |                  | $          | 429                     |       | $ | 1,837 |   | $ | 1,806 |   | $ | 1,872 |   | $ | 2,262 |   |
| **Tax Benefit Recognized** |       | 209                    |       | 152                   |       | 661                     |       | 657 |   | 663 |   | 822 |   |
|                            |            |                        |            |                       |            |                         |            |  |  |  |  |  |  |  |  |  |  |  |  |

 

Activityfor our various stock plans for the nine months ended September 30, 2009is summarized below:

 

**Performance-Based Restricted Stock Awards**

 

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

 
| ** **                                  | ** ** | **Fair Value of Grants Outstanding at September 30,** | ** ** |
|---------------------------------------------|------------|------------------------------------------------------------|------------|
| ** **                                  | ** ** | **2009**                                                   | ** ** | **2008** | ** ** |
| **Risk-free interest rate**                 |       | 0.07% to 1.05%                                             |       | 1.50% to 2.09% |   |
| **Expected volatility of Empire stock**     |       | 28.9%                                                      |       | 21.5% |   |
| **Expected volatility of peer group stock** |       | 21.9% to 80.3%                                             |       | 15.9% to 45.3% |   |
| **Expected dividend yield on Empire stock** |       | 7.6%                                                       |       | 5.9% |   |
| **Expected forfeiture rates**               |       | 3%                                                         |       | 3% |   |
| **Plan cycle**                              |       | 3 years                                                    |       | 3 years |   |
| **Fair value percentage**                   |       | 112.0% to 117.0%                                           |       | 122.0% to 150.0% |   |
| **Weighted average fair value per share**   |       | $22.39                                                     |       | $29.01 |   |

 

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Non-vested restricted stockawards (based on target number) as of September 30, 2009 and 2008 andchanges during the nine months ended September 30, 2009 and 2008 were asfollows:

 
| ** **                          | ** ** | **2009**      | ** ** | **2008**             | ** ** |
|-------------------------------------|------------|---------------|------------|----------------------|------------|
| ** **                          | ** ** | **Number**    | ** ** | **Weighted Average** | ** ** | **Number** | ** ** | **Weighted Average** | ** ** |
| ** **                          | ** ** | **of shares** | ** ** | **Grant Date Price** | ** ** | **of shares** | ** ** | **Grant Date Price** | ** ** |
| **Outstanding 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 September 30,** |       | 52,200        |       | $                    | 21.57      |   | 52,300 |   | $ | 22.64 |   |

 

At September 30, 2009,there was $0.4 million of total unrecognized compensation cost related toestimated outstanding awards. This cost will be recognized over the outstandingyears remaining 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 September 30,2009 and 2008, under a Black-Scholes methodology. The assumptions used in thevaluations are shown below:

 
| ** **                                  | ** ** | **Fair Value of Grants Outstanding at September 30,** | ** ** |
|---------------------------------------------|------------|------------------------------------------------------------|------------|
| ** **                                  | ** ** | **2009**                                                   | ** ** | **2008** | ** ** |
| **Risk-free  interest rate**                |       | 1.01% to 2.64%                                             |       | 2.19% to 3.28% |   |
| **Expected  dividend yield**                |       | 7.6%                                                       |       | 5.9% |   |
| **Expected  volatility**                    |       | 24.0%                                                      |       | 21.0% |   |
| **Expected  life in months**                |       | 78                                                         |       | 78 |   |
| **Market  value**                           |       | $ 18.09                                               |       | $ 21.35 |   |
| **Weighted  average fair value per option** |       | $  0.82                                          |       | $  1.75 |   |

 

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

 
| ** **                             | ** ** | **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  September 30,** |       | 232,600     |       | $                    | 22.19      |   | 205,600 |   | $ | 22.73 |   |
| **Exercisable at  September 30,** |       | 85,000      |       | $                    | 22.46      |   | 43,300 |   | $ | 22.67 |   |

 

Theaggregate intrinsic value at September 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 September 30, 2009was $18.12 to $23.81. The weighted-average remaining contractual life ofoutstanding options at September 30, 2009 and 2008 was 6.8 years and 7.3years, respectively. As of September 30, 2009, there was $0.2 million oftotal unrecognized compensation expense related to the non-vested options andrelated dividend equivalents granted under the plan. That cost will berecognized over a period of 1 to 3 years.

 

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**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 September 30, 2009, there were 397,744 shares available for issuancein this plan.

 
| ** **                                          | ** ** | **2009** | ** ** | **2008** | ** ** |
|-----------------------------------------------------|------------|----------|------------|----------|------------|
| **Subscriptions outstanding at  September 30** |       | 69,725   |       | 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 | % |
| **Expected 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 September 30:

 
| ** **                                         | ** ** | **Three  Months  Ended** | ** ** | **Three  Months  Ended** | ** ** | **Nine  Months  Ended** | ** ** | **Nine  Months  Ended** | ** ** | **Twelve  Months  Ended** | ** ** | **Twelve  Months  Ended** | ** ** |
|----------------------------------------------------|------------|--------------------------|------------|--------------------------|------------|-------------------------|------------|-------------------------|------------|---------------------------|------------|---------------------------|------------|
| ** **                                         | ** ** | **2009**                 | ** ** | **2008**                 | ** ** | **2009**                | ** ** | **2008**                | ** ** | **2009**                  | ** ** | **2008**                  | ** ** |
| Electric  transmission and distribution expense    |       | $                        | 2,829      |                     | $          | 2,829                   |       | $                       | 8,165      |                      | $          | 8,172                     |       | $ | 10,884 |   | $ | 10,715 |   |
| Natural  gas transmission and distribution expense |       | 540                      |       | 490                      |       | 1,614                   |       | 1,440                   |       | 2,169                     |       | 1,908                     |       |
| Power  operation expense (other than fuel)         |       | 3,442                    |       | 2,987                    |       | 9,568                   |       | 8,415                   |       | 12,823                    |       | 11,143                    |       |
| Customer  accounts and assistance expense          |       | 2,687                    |       | 2,532                    |       | 7,874                   |       | 7,519                   |       | 10,522                    |       | 9,961                     |       |
| Employee  pension expense (1)                      |       | 1,456                    |       | 1,449                    |       | 4,143                   |       | 4,571                   |       | 5,464                     |       | 6,131                     |       |
| Employee  healthcare plan (1)                      |       | 1,843                    |       | 1,730                    |       | 4,535                   |       | 5,616                   |       | 6,055                     |       | 7,436                     |       |
| General  office supplies and expense               |       | 2,675                    |       | 2,504                    |       | 7,500                   |       | 7,346                   |       | 9,484                     |       | 9,950                     |       |
| Administrative  and general expense                |       | 2,592                    |       | 2,664                    |       | 8,442                   |       | 8,152                   |       | 12,017                    |       | 10,797                    |       |
| Allowance  for uncollectible accounts              |       | 741                      |       | 1,172                    |       | 2,541                   |       | 2,623                   |       | 2,862                     |       | 4,104                     |       |
| Miscellaneous  expense                             |       | 49                       |       | 47                       |       | 49                      |       | 111                     |       | 104                       |       | 229                       |       |
| Total                                              |       | $                        | 18,854     |                     | $          | 18,404                  |       | $                       | 54,431     |                      | $          | 53,965                    |       | $ | 72,384 |   | $ | 72,374 |   |

 

----

(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 asthree segments:  electric, gas and other.As part of our electric segment, we also provide water service to three townsin Missouri. The other segment consists of our non-regulated businesses,primarily a subsidiary for our fiber optics business.

 

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

 
| ** **                              | ** ** | **For the quarter ended September 30, 2009** | ** ** |
|-----------------------------------------|------------|---------------------------------------------------|------------|
| **($-000’s)**                      | ** ** | **Electric**                                      | ** ** | **Gas** | ** ** | **Other** | ** ** | **Eliminations** | ** ** | **Total** | ** ** |
| **Statement of Operations Information** |       |                                              |       |   |   |   |   |   |   |   |   |
| Revenues                                |       | $                                                 | 121,961    |   | $ | 4,795 |   | $ | 1,445 |   | $ | (148 | ) | $ | 128,053 |   |
| Depreciation  and amortization          |       | 12,150                                            |       | 504 |   | 380 |   | — |   | 13,034 |   |
| Federal  and state income taxes         |       | 7,315                                             |       | (643 | ) | 206 |   | — |   | 6,878 |   |
| Operating  income                       |       | 23,375                                            |       | (90 | ) | 392 |   | — |   | 23,677 |   |
| Interest  income                        |       | 48                                                |       | 75 |   | — |   | (81 | ) | 42 |   |
| Interest  expense                       |       | 11,119                                            |       | 986 |   | 10 |   | (81 | ) | 12,034 |   |
| Income  from AFUDC (debt and equity)    |       | 3,340                                             |       | — |   | — |   | — |   | 3,340 |   |
| Net  income                             |       | 15,530                                            |       | (1,036 | ) | 335 |   | — |   | 14,829 |   |
| ** **                              |       |                                              |       |   |   |   |   |   |   |   |   |
| **Capital Expenditures**                |       | $                                                 | 37,674     |   | $ | 699 |   | $ | 122 |   |   |   | $ | 38,495 |   |
|                                         |            |                                                   |            |  |  |  |  |  |  |  |  |  |  |  |  |  |

 
| ** **                              | ** ** | **For the quarter ended September 30, 2008** | ** ** |
|-----------------------------------------|------------|---------------------------------------------------|------------|
| **($-000’s)**                      | ** ** | **Electric**                                      | ** ** | **Gas** | ** ** | **Other** | ** ** | **Eliminations** | ** ** | **Total** | ** ** |
| **Statement of Operations Information** |       |                                              |       |   |   |   |   |   |   |   |   |
| Revenues                                |       | $                                                 | 131,395    |   | $ | 6,056 |   | $ | 1,366 |   | $ | (132 | ) | $ | 138,685 |   |
| Depreciation  and amortization          |       | 12,578                                            |       | 482 |   | 333 |   | — |   | 13,393 |   |
| Federal  and state income taxes         |       | 10,491                                            |       | (754 | ) | 188 |   | — |   | 9,925 |   |
| Operating  income                       |       | 27,960                                            |       | (293 | ) | 352 |   | — |   | 28,019 |   |
| Interest  income                        |       | 402                                               |       | 93 |   | — |   | (129 | ) | 366 |   |
| Interest  expense                       |       | 10,286                                            |       | 990 |   | 46 |   | (129 | ) | 11,193 |   |
| Income  from AFUDC (debt and equity)    |       | 3,378                                             |       | 1 |   | — |   | — |   | 3,379 |   |
| Net  income                             |       | 21,108                                            |       | (1,234 | ) | 306 |   | — |   | 20,180 |   |
| ** **                              |       |                                              |       |   |   |   |   |   |   |   |   |
| **Capital Expenditures**                |       | $                                                 | 47,302     |   | $ | 734 |   | $ | 400 |   |   |   | $ | 48,436 |   |
|                                         |            |                                                   |            |  |  |  |  |  |  |  |  |  |  |  |  |  |

 
| ** **                              | ** ** | **For the nine months ended September 30, 2009** | ** ** |
|-----------------------------------------|------------|-------------------------------------------------------|------------|
| **($-000’s)**                      | ** ** | **Electric**                                          | ** ** | **Gas** | ** ** | **Other** | ** ** | **Eliminations** | ** ** | **Total** | ** ** |
| **Statement of Operations Information** |       |                                                  |       |   |   |   |   |   |   |   |   |
| Revenues                                |       | $                                                     | 331,831    |   | $ | 40,800 |   | $ | 4,123 |   | $ | (456 | ) | $ | 376,298 |   |
| Depreciation  and amortization          |       | 35,868                                                |       | 1,507 |   | 1,071 |   | — |   | 38,446 |   |
| Federal  and state income taxes         |       | 15,978                                                |       | (66 | ) | 622 |   | — |   | 16,534 |   |
| Operating  income                       |       | 54,573                                                |       | 2,678 |   | 1,108 |   | — |   | 58,359 |   |
| Interest  income                        |       | 184                                                   |       | 342 |   | — |   | (346 | ) | 180 |   |
| Interest  expense                       |       | 32,520                                                |       | 2,970 |   | 50 |   | (346 | ) | 35,194 |   |
| Income  from AFUDC (debt and equity)    |       | 10,278                                                |       | 1 |   | — |   | — |   | 10,279 |   |
| Net  income                             |       | 32,392                                                |       | (35 | ) | 1,011 |   | — |   | 33,368 |   |
| ** **                              |       |                                                  |       |   |   |   |   |   |   |   |   |
| **Capital Expenditures**                |       | $                                                     | 118,341    |   | $ | 1,554 |   | $ | 914 |   |   |   | $ | 120,809 |   |
|                                         |            |                                                       |            |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

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| ** **                              | ** ** | **For the nine months ended September 30, 2008** | ** ** |
|-----------------------------------------|------------|-------------------------------------------------------|------------|
| **($-000’s)**                      | ** ** | **Electric**                                          | ** ** | **Gas** | ** ** | **Other** | ** ** | **Eliminations** | ** ** | **Total** | ** ** |
| **Statement of Operations Information** |       |                                                  |       |   |   |   |   |   |   |   |   |
| Revenues                                |       | $                                                     | 341,078    |   | $ | 42,480 |   | $ | 3,748 |   | $ | (396 | ) | $ | 386,910 |   |
| Depreciation  and amortization          |       | 38,451                                                |       | 1,443 |   | 981 |   | — |   | 40,875 |   |
| Federal  and state income taxes         |       | 14,447                                                |       | 352 |   | 486 |   | — |   | 15,285 |   |
| Operating  income                       |       | 50,618                                                |       | 3,347 |   | 939 |   | — |   | 54,904 |   |
| Interest  income                        |       | 1,057                                                 |       | 356 |   | — |   | (424 | ) | 989 |   |
| Interest  expense                       |       | 28,944                                                |       | 2,971 |   | 149 |   | (424 | ) | 31,640 |   |
| Income  from AFUDC (debt and equity)    |       | 8,854                                                 |       | 3 |   | — |   | — |   | 8,857 |   |
| Net  income                             |       | 30,624                                                |       | 573 |   | 790 |   | — |   | 31,987 |   |
| ** **                              |       |                                                  |       |   |   |   |   |   |   |   |   |
| **Capital Expenditures**                |       | $                                                     | 150,061    |   | $ | 1,624 |   | $ | 1,478 |   |   |   | $ | 153,163 |   |
|                                         |            |                                                       |            |  |  |  |  |  |  |  |  |  |  |  |  |  |

 
| ** **                              | ** ** | **For the twelve months ended September 30, 2009** | ** ** |
|-----------------------------------------|------------|---------------------------------------------------------|------------|
| **($-000’s)**                      | ** ** | **Electric**                                            | ** ** | **Gas** | ** ** | **Other** | ** ** | **Eliminations** | ** ** | **Total** | ** ** |
| **Statement of Operations Information** |       |                                                    |       |   |   |   |   |   |   |   |   |
| Revenues                                |       | $                                                       | 439,001    |   | $ | 63,759 |   | $ | 5,380 |   | $ | (589 | ) | $ | 507,551 |   |
| Depreciation  and amortization          |       | 47,721                                                  |       | 2,004 |   | 1,407 |   | — |   | 51,132 |   |
| Federal  and state income taxes         |       | 19,296                                                  |       | 569 |   | 510 |   | — |   | 20,375 |   |
| Operating  income                       |       | 68,381                                                  |       | 4,752 |   | 1,334 |   |   |   | 74,467 |   |
| Interest  income                        |       | 289                                                     |       | 375 |   | — |   | (416 | ) | 248 |   |
| Interest  expense                       |       | 43,203                                                  |       | 3,961 |   | 103 |   | (416 | ) | 46,851 |   |
| Income  from AFUDC (debt and equity)    |       | 13,932                                                  |       | 8 |   | — |   | — |   | 13,940 |   |
| Net  income                             |       | 39,204                                                  |       | 1,070 |   | 830 |   | — |   | 41,104 |   |
| ** **                              |       |                                                    |       |   |   |   |   |   |   |   |   |
| **Capital Expenditures**                |       | $                                                       | 169,036    |   | $ | 2,069 |   | $ | 1,387 |   |   |   | $ | 172,492 |   |
|                                         |            |                                                         |            |  |  |  |  |  |  |  |  |  |  |  |  |  |

 
| ** **                              | ** ** | **For the twelve months ended September 30, 2008** | ** ** |
|-----------------------------------------|------------|---------------------------------------------------------|------------|
| **($-000’s)**                      | ** ** | **Electric**                                            | ** ** | **Gas** | ** ** | **Other** | ** ** | **Eliminations** | ** ** | **Total** | ** ** |
| **Statement of Operations Information** |       |                                                    |       |   |   |   |   |   |   |   |   |
| Revenues                                |       | $                                                       | 436,792    |   | $ | 60,687 |   | $ | 4,723 |   | $ | (519 | ) | $ | 501,683 |   |
| Depreciation  and amortization          |       | 51,120                                                  |       | 1,920 |   | 1,287 |   | — |   | 54,327 |   |
| Federal  and state income taxes         |       | 12,236                                                  |       | 923 |   | 699 |   | — |   | 13,858 |   |
| Operating  income                       |       | 56,437                                                  |       | 5,372 |   | 954 |   |   |   | 62,763 |   |
| Interest  income                        |       | 840                                                     |       | 434 |   | — |   | (212 | ) | 1,062 |   |
| Interest  expense                       |       | 38,131                                                  |       | 3,982 |   | (128 | ) | (212 | ) | 41,773 |   |
| Income  from AFUDC (debt and equity)    |       | 10,988                                                  |       | 2 |   | — |   | — |   | 10,990 |   |
| Net  Income                             |       | 29,009                                                  |       | 1,522 |   | 1,054 |   | — |   | 31,585 |   |
| ** **                              |       |                                                    |       |   |   |   |   |   |   |   |   |
| **Capital Expenditures**                |       | $                                                       | 201,484    |   | $ | 2,089 |   | $ | 3,255 |   |   |   | $ | 206,828 |   |
|                                         |            |                                                         |            |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

**As of September 30, 2009**

 
| **($-000’s)**            | ** ** | **Electric** | ** ** | **Ga****s(1)** | ** ** | **Other** | ** ** | **Eliminations** | ** ** | **Total** | ** ** |
|-------------------------------|------------|--------------|------------|----------------|------------|-----------|------------|------------------|------------|-----------|------------|
| **Balance Sheet Information** |       |         |       |           |       |      |       |             |       |      |       |
| Total  assets                 |       | $            | 1,713,740  |           | $          | 133,378   |       | $                | 21,981     |      | $          | (82,234 | ) | $ | 1,786,865 |   |
|                               |            |              |            |                |            |           |            |                  |            |           |            |  |  |  |  |  |

 

----

(1) Includesgoodwill of $39,492.

 

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**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**

 

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

 
| ** **                                                 | ** ** | **Three Months Ended** | ** ** | **Nine Months Ended** | ** ** | **Twelve Months Ended** | ** ** |
|------------------------------------------------------------|------------|------------------------|------------|-----------------------|------------|-------------------------|------------|
| ** **                                                 | ** ** | **2009**               | ** ** | **2008**              | ** ** | **2009**                | ** ** | **2008** | ** ** | **2009** | ** ** | **2008** | ** ** |
| Consolidated  effective federal and state income tax rates |       | 31.7                   | %          | 33.0                  | %          | 33.1                    | %          | 32.3 | % | 33.1 | % | 30.5 | % |

 

Therate for the third quarter of 2009 is lower primarily due to lower income. Therates for the nine months ended and twelve months ended periods are higherprimarily due to lower tax benefits received from cost of plant retirementexpenditures. Our cost of retirement expenditures was unusually high during thetwelve months ended September 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.

 

We decreased our estimate ofunrecognized tax benefits by an immaterial amount during the quarter ended March 31,2008 as a review of certain amended returns by the Joint Committee on Taxationwas completed. The Joint Committee accepted our tax position which led us torecognize certain tax benefits previously unrecognized. We do not expect anysignificant changes to our unrecognized tax benefits over the next twelvemonths. The reserve balance related to unrecognized tax benefits as of December 31,2008 was $2,176,000 and at September 30, 2009 was $906,000. The change ismostly due to the statute of limitations expiring on certain unrecognized taxbenefits.

 

Ourconsolidated provision for income taxes decreased approximately $3.0 millionduring the third quarter of 2009 as compared to the third quarter of 2008primarily due to decreased income. Our consolidated provision for income taxesincreased approximately $1.5 million during the nine months ended September 30,2009 and $7.2 million during the twelve months ended September 30, 2009 ascompared to the same periods in 2008 mainly due to increased income.

 

**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 September 30 2009,86.5% of our gross operating revenues were provided from sales from our

 

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electricsegment (including 0.3% from the sale of water),12.6% from our gas segment and0.9% from our other segment.

 

***Earnings***

 

During the third quarter of 2009, basicearnings per weighted average share of common stock were $0.43 as compared to$0.60 in the third quarter of 2008 and diluted earnings per weighted averageshare of common stock were $0.43 as compared to $0.59 for the third quarter of2008. For the nine months ended September 30, 2009, basic and dilutedearnings per weighted average share of common stock were $0.97 as compared to$0.95 for the nine months ended September 30, 2008. For the twelve monthsended September 30, 2009, basic and diluted earnings per weighted averageshare of common stock were $1.20 as compared to $0.95 for the twelve monthsended September 30, 2008.

 

Third quarter 2009 weather was the coolestsummer in the past 30 years, which affected both customer demand and generationneeds and was the primary driver for lower earnings in 2009 as compared to2008. Mild weather, which reduced both on-system and off-system sales, andincreased maintenance costs were the primary negative drivers for the ninemonth and twelve month periods. The primary positive drivers for all periodspresented were decreased fuel and purchased power costs which resulted from thedecreased customer demand, and rate changes, mainly due to our 2008 Missourirate case.

 

The following reconciliation of basicearnings per share between the three months, nine months and twelve monthsended September 30, 2008 versus September 30, 2009 is a non-GAAPpresentation. We believe this information is useful in understanding thefluctuation in earnings per share between the prior and current years. Thereconciliation presents the after tax impact of significant items andcomponents of the statement of operations on a per share basis before theimpact of additional stock issuances which is presented separately. Earningsper share for the three months, nine months and twelve months ended September 30,2008 and 2009 shown in the reconciliation are presented on a GAAP basis and arethe same as the amounts included in the statements of operations. Thisreconciliation may not be comparable to other companies or more useful than theGAAP presentation included in the statements of operations.

 
| ** **                                   | ** ** | **Three Months  Ended** | ** ** | **Nine Months  Ended** | ** ** | **Twelve Months  Ended** | ** ** |
|----------------------------------------------|------------|-------------------------|------------|------------------------|------------|--------------------------|------------|
| **Earnings Per Share — 2008**           | ** ** | **$**                   | **0.60**   | ** **             | **$**      | **0.95**                 | ** ** | **$** | **0.95** | ** ** |
| ** **                                   | ** ** | ** **              | ** ** | ** **             | ** ** | ** **               | ** ** |
| **Revenues**                                 |       |                    |       |                   |       |                     |       |
| Electric  on-system                          |       | $                       | (0.08      | )                      | $          | 0.09                     |       | $ | 0.27 |   |
| Electric  off-system and other               |       | (0.11                   | )          | (0.28                  | )          | (0.22                    | )          |
| Gas                                          |       | (0.02                   | )          | (0.03                  | )          | 0.06                     |       |
| Other                                        |       | 0.00                    |       | 0.01                   |       | 0.01                     |       |
| **Expenses**                                 | ** ** | ** **              | ** ** | ** **             | ** ** | ** **               | ** ** |
| Electric  fuel and purchased power           |       | 0.06                    |       | 0.37                   |       | 0.45                     |       |
| Cost  of natural gas sold and transported    |       | 0.03                    |       | 0.02                   |       | (0.08                    | )          |
| Regulated  — electric segment           |       | (0.01                   | )          | (0.01                  | )          | 0.00                     |       |
| Regulated  —gas segment                 |       | 0.00                    |       | 0.00                   |       | 0.00                     |       |
| Other  segment                               |       | 0.00                    |       | 0.00                   |       | 0.00                     |       |
| Maintenance  and repairs                     |       | (0.02                   | )          | (0.11                  | )          | (0.13                    | )          |
| Depreciation  and amortization               |       | 0.01                    |       | 0.05                   |       | 0.07                     |       |
| Other  taxes                                 |       | 0.00                    |       | (0.02                  | )          | (0.01                    | )          |
| Interest  charges                            |       | (0.02                   | )          | (0.07                  | )          | (0.11                    | )          |
| AFUDC                                        |       | 0.00                    |       | 0.03                   |       | 0.06                     |       |
| Gain  on sale of assets                      |       | —                  |       | —                 |       | (0.03                    | )          |
| Change  in effective income tax rates        |       | 0.01                    |       | (0.01                  | )          | (0.05                    | )          |
| Gain  on sale of land                        |       | —                  |       | 0.01                   |       | 0.01                     |       |
| Other  income and deductions                 |       | (0.01                   | )          | (0.02                  | )          | (0.02                    | )          |
| Dilutive  effect of additional shares issued |       | (0.01                   | )          | (0.01                  | )          | (0.03                    | )          |
| **Earnings Per Share — 2009**           | ** ** | **$**                   | **0.43**   | ** **             | **$**      | **0.97**                 | ** ** | **$** | **1.20** | ** ** |

 

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**RecentActivities**

 

***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 and $0.9 million in the third quarter of 2009. Construction accounting,for purposes of the regulatory plan, allows us to defer certain charges asregulatory assets, including depreciation and carrying costs, related tooperation of the facilities until the facilities are ultimately included in ourrate base. The amounts deferred, which began at the in-service date for Iatan 1and will also be deferred for Iatan 2 at its in-service date, will then beamortized over the life of the plants once they are in our rate base. Theregulatory plan covers the 150 megawatt V84.3A2 combustion turbine (Unit 12)that began commercial operation on April 10, 2007 at our Riverton plant,the environmental upgrades at Asbury, which were completed in 2008,environmental upgrades at Iatan 1 and the construction of the Iatan 2facilities. See Note 3 of “Notes to Consolidated Financial Statements(Unaudited)”.

 

***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 was undamaged and continued to operate asnormal. The cost to replace the turbine was in excess of the $1.5 millioninsurance deductible on the unit. We expect to recover all the costs frominsurance proceeds in excess of the $1.5 million deductible. The unplannedoutage did not have a material financial impact. Unit 2-1 returned to servicein October 2009.

 

***Energy Center Engine Failure***

 

On September 28, 2009,we experienced a failure on Energy Center Unit 3, Engine A. We believe the costwill exceed our insurance deductible, which is $500,000. Engine B on this unitis operational and the unit is capable of about 50 percent of normalcapability. We do not expect this unplanned outage to have a material financialimpact.

 

***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 associatedwith the restoration effort due to the wind storm were approximately $6.0million, of which $5.3 million was capitalized as additions to our utilityplant and approximately $0.7 million was maintenance expense that was deferredas a regulatory asset as we believe it is probable that these costs will berecoverable in future electric rate cases.

 

***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 

 

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Administration(SWPA), in coordination with us and our relevant public service commissions, todetermine our economic detriment.

 

TheSWPA published its Final Determination Report on January 23, 2009documenting the procedure they intended to use to calculate the present valueof the future lifetime replacement cost of the electrical energy and capacitylost due to the White River Minimum Flows project at Ozark Beach. The actualhydropower compensation values were to be calculated using the method presentedin the Final Determination and current values for the specified parametersbased on the official implementation date. Assuming a January 1, 2011 dateof implementation for the White River Minimum Flows project and November 2008values for the specified parameters, the SWPA’s determination at that timeresulted in a present value for the estimated future lifetime replacement costsof the electrical energy and capacity at Ozark Beach of $41,319,400. On June 8,2009, the SWPA published a draft addendum to its January 2009 FinalDetermination Report documenting proposed changes to the SWPA’s methodology,including the inclusion of an additional discount rate source to be used by theSWPA in determination of the present value of the losses. Assuming a January 1,2011 date of implementation for the White River Minimum Flows project andcurrent values for the specified parameters, the SWPA’s Draft Addendum to itsFinal Determination results in a present value of $22,340,800 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.

 

***Regulatory Matters***

 

On November 4, 2009, we filed a request with the KansasCorporation Commission (KCC) for an annual increase in base rates for ourKansas electric customers in the amount of $5.2 million, or 24.6%. This requestis primarily to allow us to recover capital expenditures associated withenvironmental upgrades at Iatan 1 completed in 2009 and at our Asbury plantcompleted in 2008 and our investment in new generating units at Iatan 2, thePlum Point Generating Station and our Riverton 12 unit that went on line in2007.

 

On October 29, 2009, we filed a request with the MPSC for anannual increase in base rates for our Missouri electric customers in the amountof $68.2 million, or 19.6%. This request is primarily to allow us to recover capitalexpenditures associated with environmental upgrades at Iatan 1 and ourinvestment in new generating units at Iatan 2 and the Plum Point GeneratingStation. The Signatory Parties are currently in discussions about procedures tobe used in this case, including the timing of the consideration and raterecovery of our investments in the three generating facilities and otherexpenditures.

 

OnJune 5, 2009, we filed a request with the MPSC for an annual increase in baserates for our Missouri gas customers in the amount of $2.9 million, or 4.9%. Inthis filing, we requested recovery of the ongoing cost of operating andmaintaining our 1,200-mile gas distribution system and a return on equity of11.3%. 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. Theseactions were consolidated into one proceeding. Briefs were 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. On September 3,2009, the Jasper County Circuit Court dismissed the petition with prejudice. OnOctober 7, 2009, the OPC appealed the Jasper County Circuit Court decisionto the Missouri Court of Appeals – Southern District.

 

For additional information, see “Rate Matters” below.

 

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***Financings***

 

Duringthe third quarter of 2009, we issued and sold 1,542,682 shares of our commonstock, pursuant to our equity distribution agreement with UBS Securities LLC(UBS), at an average price per share of $18.09, resulting in proceeds to us ofapproximately $26.7 million (after payment of approximately $1.2 million incommissions to the sales agent). Through October 5, 2009, in theaggregate, we have issued and sold 1,692,290 shares pursuant to the program,resulting in net proceeds to us of approximately $29.3 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. On October 22, 2009 we amended the equitydistribution agreement to increase the aggregate offering amount under theprogram from $60 million to $120 million.

 

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 September 30,2009.

 

***Gas Storage Contract***

 

Wehave signed an agreement with Southern Star to purchase one million Dths offirm gas storage service capacity for a period of five years beginning in April 2011.The reservation charge for this storage capacity is approximately $1.1 millionannually. This storage capacity will enable us to better manage our natural gascommodity and transportation needs for our electric segment.

 

**RESULTS OF OPERATIONS**

 

The following discussion analyzes significant changes in the results ofoperations for the three-month, nine-month and twelve-month periods ended September 30,2009, compared to the same periods ended September 30, 2008.

 

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

 
| ** **              | ** ** | **Quarter Ended** | ** ** | **Nine Months Ended** | ** ** | **Twelve Months Ended** | ** ** |
|-------------------------|------------|-------------------|------------|-----------------------|------------|-------------------------|------------|
| ** **              | ** ** | **2009**          | ** ** | **2008**              | ** ** | **2009**                | ** ** | **2008** | ** ** | **2009** | ** ** | **2008** | ** ** |
| Income  from operations |       |              |       |                  |       |                    |       |   |   |   |   |   |   |
| Electric                |       | $                 | 15.5       |                  | $          | 21.1                    |       | $ | 32.4 |   | $ | 30.6 |   | $ | 39.2 |   | $ | 29.0 |   |
| Gas                     |       | (1.0              | )          | (1.2                  | )          | (0.0                    | )          | 0.6 |   | 1.1 |   | 1.5 |   |
| Other                   |       | 0.3               |       | 0.3                   |       | 1.0                     |       | 0.8 |   | 0.8 |   | 1.1 |   |
| Net income              |       | $                 | 14.8       |                  | $          | 20.2                    |       | $ | 33.4 |   | $ | 32.0 |   | $ | 41.1 |   | $ | 31.6 |   |

 

----

**Differences could occur due to rounding.*

 

***Electric Segment***

 

**Overview**

 

Our electric segment income for the third quarter of 2009 was $15.5million as compared to $21.1 million for the third quarter of 2008.

 

Electric operating revenues comprised approximately 95.2% of our totaloperating revenues during the third quarter of 2009. Of our total electricoperating revenues during the third quarter of 2009, approximately 41.1% werefrom residential customers, 32.3% from commercial customers,

 

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16.2% from industrial customers, 4.2% from wholesale on-systemcustomers, 2.2% from wholesale off-system transactions, 2.8% from otherelectric revenues, primarily public authorities, and 1.2% from miscellaneoussources. The percentage of revenues provided from our wholesale off-systemtransactions decreased during the third quarter of 2009 as compared to thethird quarter of 2008, primarily due to decreased market demand resulting frommilder weather in the third quarter of 2009 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 September 30,were as follows:

 
| ** **            | ** ** | **kWh Sales**     | ** ** |
|-----------------------|------------|-------------------|------------|
| ** **            | ** ** | **(in millions)** | ** ** |
| ** **            | ** ** | **3 Months**      | ** ** | **3 Months** | ** ** | ** ** | ** ** | **9 Months** | ** ** | **9 Months** | ** ** | ** ** | ** ** | **12 Months** | ** ** | **12 Months** | ** ** | ** ** | ** ** |
| ** **            | ** ** | **Ended**         | ** ** | **Ended** | ** ** | **%** | ** ** | **Ended** | ** ** | **Ended** | ** ** | **%** | ** ** | **Ended** | ** ** | **Ended** | ** ** | **%** | ** ** |
| **Customer Class**    | ** ** | **2009**          | ** ** | **2008** | ** ** | **Change*** | ** ** | **2009** | ** ** | **2008** | ** ** | **Change*** | ** ** | **2009** | ** ** | **2008** | ** ** | **Change*** | ** ** |
| Residential           |       | 471.0             |       | 503.6 |   | (6.5 | )% | 1,409.1 |   | 1,478.7 |   | (4.7 | )% | 1,883.3 |   | 1,917.4 |   | (1.8 | )% |
| Commercial            |       | 408.3             |       | 446.4 |   | (8.5 | ) | 1,188.2 |   | 1,217.9 |   | (2.4 | ) | 1,592.4 |   | 1,613.1 |   | (1.3 | ) |
| Industrial            |       | 265.6             |       | 289.3 |   | (8.2 | ) | 757.9 |   | 820.9 |   | (7.7 | ) | 1,010.3 |   | 1,088.1 |   | (7.1 | ) |
| Wholesale on-system   |       | 89.4              |       | 94.3 |   | (5.2 | ) | 252.9 |   | 263.4 |   | (4.0 | ) | 334.0 |   | 344.8 |   | (3.1 | ) |
| Other**               |       | 30.8              |       | 32.1 |   | (3.8 | ) | 92.8 |   | 94.1 |   | (1.4 | ) | 122.5 |   | 124.5 |   | (0.2 | ) |
| Total on-system sales |       | 1,265.1           |       | 1,365.7 |   | (7.4 | ) | 3,700.9 |   | 3,875.0 |   | (4.5 | ) | 4,942.5 |   | 5,087.9 |   | (2.9 | ) |
| Off-system            |       | 100.6             |       | 164.1 |   | (38.7 | ) | 346.3 |   | 473.8 |   | (26.9 | ) | 560.6 |   | 563.8 |   | (0.6 | ) |
| Total KWh Sales       |       | 1,365.7           |       | 1,529.8 |   | (10.7 | ) | 4,047.2 |   | 4,348.8 |   | (6.9 | ) | 5,503.1 |   | 5,651.7 |   | (2.6 | ) |

 

----

**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)**                | ** ** |
| ** **                        | ** ** | **3 Months**                            | ** ** | **3 Months** | ** ** | ** ** | ** ** | **9 Months** | ** ** | **9 Months** | ** ** | ** ** | ** ** | **12 Months** | ** ** | **12 Months** | ** ** | ** ** | ** ** |
| ** **                        | ** ** | **Ended**                               | ** ** | **Ended** | ** ** | **%** | ** ** | **Ended** | ** ** | **Ended** | ** ** | **%** | ** ** | **Ended** | ** ** | **Ended** | ** ** | **%** | ** ** |
| **Customer Class**                | ** ** | **2009**                                | ** ** | **2008** | ** ** | **Change*** | ** ** | **2009** | ** ** | **2008** | ** ** | **Change*** | ** ** | **2009** | ** ** | **2008** | ** ** | **Change*** | ** ** |
| Residential                       |       | $                                       | 49.9       |   | $ | 51.1 |   | (2.2 | )% | $ | 138.0 |   | $ | 136.1 |   | 1.4 | % | $ | 181.2 |   | $ | 173.8 |   | 4.3 | % |
| Commercial                        |       | 39.3                                    |       | 41.0 |   | (4.1 | ) | 104.2 |   | 100.5 |   | 3.6 |   | 136.5 |   | 130.0 |   | 5.0 |   |
| Industrial                        |       | 19.7                                    |       | 20.5 |   | (4.1 | ) | 51.3 |   | 51.9 |   | (1.1 | ) | 66.8 |   | 67.2 |   | (0.6 | ) |
| Wholesale on-system               |       | 5.1                                     |       | 5.5 |   | (7.5 | ) | 14.1 |   | 15.0 |   | (5.9 | ) | 18.4 |   | 19.7 |   | (6.7 | ) |
| Other**                           |       | 3.3                                     |       | 3.2 |   | 4.2 |   | 8.9 |   | 8.4 |   | 5.6 |   | 11.5 |   | 10.9 |   | 5.5 |   |
| Total on-system revenues          |       | $                                       | 117.3      |   | $ | 121.3 |   | (3.3 | ) | $ | 316.5 |   | $ | 311.9 |   | 1.5 |   | $ | 414.4 |   | $ | 401.6 |   | 3.2 |   |
| Off-system                        |       | 2.7                                     |       | 7.8 |   | (65.7 | ) | 9.3 |   | 22.6 |   | (59.1 | ) | 16.3 |   | 26.7 |   | (38.9 | ) |
| Total revenues from kWh sales     |       | 120.0                                   |       | 129.1 |   | (7.0 | ) | 325.8 |   | 334.5 |   | (2.6 | ) | 430.7 |   | 428.3 |   | 0.6 |   |
| Miscellaneous revenues***         |       | 1.5                                     |       | 1.8 |   | (17.8 | ) | 4.7 |   | 5.2 |   | (8.0 | ) | 6.5 |   | 6.7 |   | (1.8 | ) |
| Total electric operating revenues |       | $                                       | 121.5      |   | $ | 130.9 |   | (7.2 | ) | $ | 330.5 |   | $ | 339.7 |   | (2.7 | ) | $ | 437.2 |   | $ | 435.0 |   | 0.5 |   |
| Water revenues                    |       | 0.5                                     |       | 0.5 |   | (2.1 | ) | 1.3 |   | 1.4 |   | (2.0 | ) | 1.8 |   | 1.8 |   | (3.3 | ) |
| Total Electric Segment            |       |                                    |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Operating Revenues                |       | $                                       | 122.0      |   | $ | 131.4 |   | (7.2 | ) | $ | 331.8 |   | $ | 341.1 |   | (2.7 | ) | $ | 439.0 |   | $ | 436.8 |   | 0.5 |   |

 

----

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

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

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

 

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

 

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

 

KWh sales and revenues for our on-system customers decreased during thethird quarter of 2009 as compared to the third quarter of 2008 primarily due tothe mild weather in the third quarter of 2009. Revenues for our on-systemcustomers decreased approximately $3.9 million, or 3.3%. Weather and otherrelated factors decreased revenues by an estimated $10.8 million compared tolast year’s third quarter. Total cooling degree days (the cumulative number ofdegrees that the average temperature for each day during that period was above65*°* F) for the third quarter of 2009 were 23.6% lessthan the same period last year and 30.1% less than the 30-year average. Rate

 

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changes contributed an estimated $6.8 million to revenues during thethird quarter of 2009. Residential and commercial sales growth increasedrevenues an estimated $0.1 million. Our electric customer growth for the twelvemonths ended September 30, 2009 was 0.2%.

 

Residential and commercial kWh sales and revenues decreased during thethird quarter of 2009 mainly due to the cooler temperatures in the thirdquarter of 2009.

 

Industrial kWh sales decreased 8.2% mainly due to a slowdown created byeconomic uncertainty while the associated revenues decreased 4.1% as theeffects of the 2008 Missouri rate increase partially offset the economicconditions.

 

On-system wholesale kWh sales decreased during the third quarter of2009 reflecting the general economic conditions and cooler weather discussedabove. Revenues associated with these FERC-regulated sales decreased more thankWh sales as a result of the fuel adjustment clause applicable to such sales.This clause permits the distribution to customers of changes in fuel andpurchased 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 and has no effect on net income. The following tablesets forth information regarding these sales and related expenses for thequarters ended September 30:

 
| **(in millions)**         | ** ** | **2009** | ** ** | **2008** | ** ** |
|---------------------------|------------|----------|------------|----------|------------|
| EIS revenues              |       | $        | 1.4        |     | $          | 3.4 |   |
| Other revenues            |       | 1.3      |       | 4.4      |       |
| Total off-system revenues |       | 2.7      |       | 7.8      |       |
|                      |       |     |       |     |       |
| EIS expenses              |       | 1.1      |       | 2.5      |       |
| Other expenses            |       | 1.2      |       | 2.9      |       |
| Total off-system expenses |       | 2.3      |       | 5.4      |       |
|                      |       |     |       |     |       |
| Net                       |       | $        | 0.4        |     | $          | 2.4 |   |

 

Revenues and related expenses were less during the third quarter of2009 as compared to the third quarter of 2008 primarily due to decreased marketdemand and lower gas prices that made it more economical for utilities togenerate their own power rather than purchase it. Total purchased power relatedexpenses are included in our discussion of purchased power costs below.

 

**Miscellaneous Revenues**

 

Our miscellaneous revenues were $1.5 million for the third quarter of2009 as compared to $1.8 million in the third quarter of 2008. These revenuesare comprised mainly of transmission revenues, late payment fees and renewableenergy credit sales.

 

**Operating Revenue Deductions**

 

During the third quarter of 2009, total electric segment operatingexpenses decreased approximately $4.8 million (4.7%) compared with the sameperiod last year.

 

Totalfuel and purchased power expenses decreased approximately $3.4 million (6.5%)during the third 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 third quarter of 2009 and 2008.

 

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| **(in millions)**                                            | ** ** | **2009** | ** ** | **2008** | ** ** |
|--------------------------------------------------------------|------------|----------|------------|----------|------------|
| Actual fuel and purchased power expenditures                 |       | $        | 47.1       |     | $          | 49.7 |   |
| Kansas regulatory adjustments*                               |       | 0.1      |       | (0.2     | )          |
| Missouri fuel adjustment deferral*                           |       | 0.4      |       | 2.0      |       |
| Missouri fuel adjustment recovery**                          |       | 0.9      |       | —   |       |
| Unrealized gain on derivatives                               |       | (0.4     | )          | —   |       |
| Total fuel and purchased power expense per income  statement |       | $        | 48.1       |     | $          | 51.5 |   |

 

----

*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 third quarter of 2009 reflectingdecreased market demand resulting from milder weather in the third quarter of2009 as well as decreased off-system sales.

 

Summarizedin the table below are our estimated cost and volume changes in the componentsof fuel and purchased power expenses for the third quarter of 2009 as comparedto the third quarter of 2008. This table incorporates all the changes mentionedabove. As shown below, the largest impacts on fuel and purchased power costswere decreased generation by our gas-fired units and lower purchased powercosts primarily due to decreased market demand for purchased power in the thirdquarter of 2009 as a result of the mild weather.

 
| **(in millions)**                    | ** ** | **2009** | ** ** |
|--------------------------------------|------------|----------|------------|
| Coal (cost)                          |       | $        | 1.0        |   |
| Natural gas (cost)                   |       | 1.5      |       |
| Purchased power (cost)               |       | (2.6     | )          |
| Coal generation volume               |       | (0.9     | )          |
| Natural gas generation volume        |       | (2.1     | )          |
| Purchased power spot purchase volume |       | 0.6      |       |
| Other (including fuel adjustments)   |       | (0.9     | )          |
| TOTAL                                |       | $        | (3.4       | ) |

 

Regulatedoperating expenses increased approximately $0.7 million (4.2%) during the thirdquarter of 2009 as compared to the same period in 2008 primarily due toincreases of $0.7 million in professional services, $0.2 million in other steampower expense at the Asbury plant and $0.2 million in general labor costs.These increases were partially offset by a $0.4 million decrease in injuriesand damages expense.

 

Maintenance and repairs expense increased approximately $1.1 million(16.1%) in the third quarter of 2009 as compared to 2008 primarily due toincreases of $1.1 million in distribution maintenance costs (including $0.5million of ice storm related amortization) and $0.3 million in systemreliability maintenance (infrastructure inspection) costs partially offset by a$0.2 million decrease in maintenance and repairs expense at the Riverton plant.

 

Depreciation and amortization expense decreased approximately $0.4million (3.4%) during the quarter primarily due to reduced regulatoryamortization resulting from the 2008 Missouri rate case that went into effecton August 23, 2008. Other taxes increased approximately $0.3 million duringthe third quarter of 2009 due to increased property tax reflecting ouradditions to plant in service and increased municipal franchise taxes.

 

***Nine Months Ended September 30, 2009 Comparedto Nine Months Ended September 30, 2008***

 

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

 

KWh sales for our on-system customers decreased during the nine monthsended September 30, 2009 as compared to the nine months ended September 30,2008 primarily due to milder weather in the first nine months of 2009 ascompared to the same period in 2008. However,

 

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revenues for our on-system customers increased approximately $4.6million, or 1.5%. Rate changes contributed an estimated $20.1 million duringthe nine months ended September 30, 2009 while sales growth contributed anestimated $0.6 million. Weather and other related factors decreased revenues byan estimated $16.1 million compared to the nine months ended September 30,2008.

 

The decrease in residential and commercial kWh sales during the ninemonths ended September 30, 2009 was primarily due to the mild weather in2009. The related revenues increased during the first nine months of 2009,primarily as a result of the 2008 Missouri rate increase.

 

Industrial kWh sales decreased 7.7% mainly due to a slowdown created byeconomic uncertainty while the associated revenues decreased only 1.1% due tothe effects of the Missouri rate increase which partially offset the economicconditions**.**

 

On-system wholesale kWh sales decreased during the nine months ended September 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**

 

Thefollowing table sets forth information regarding our off-system sales andrelated expenses for the nine months ended September 30:

 
| **(in millions)**         | ** ** | **2009** | ** ** | **2008** | ** ** |
|---------------------------|------------|----------|------------|----------|------------|
| EIS revenues              |       | $        | 3.8        |     | $          | 10.7 |   |
| Other revenues            |       | 5.5      |       | 11.9     |       |
| Total off-system revenues |       | 9.3      |       | 22.6     |       |
|                      |       |     |       |     |       |
| EIS expenses              |       | 3.2      |       | 7.5      |       |
| Other expenses            |       | 4.7      |       | 8.8      |       |
| Total off-system expenses |       | 7.9      |       | 16.3     |       |
|                      |       |     |       |     |       |
| Net                       |       | $        | 1.4        |     | $          | 6.3 |   |

 

Revenues and related expenses were less during the nine months ended September 30,2009 as compared to the same period in 2008 primarily due to decreased marketdemand resulting from mild weather and decreased gas prices. Total purchasedpower related expenses are included in our discussion of purchased power costsbelow.

 

**Miscellaneous Revenues**

 

Our miscellaneous revenues were $4.7 million for the nine months ended September 30,2009 as compared to $5.2 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 nine months ended September 30, 2009, total electricsegment operating expenses decreased approximately $13.2 million (4.6%)compared with the same period last year.

 

Totalfuel and purchased power expenses decreased approximately $18.9 million (12.2%)during the nine months ended September 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 nine months ended September 30, 2009and 2008.

 

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| **(in millions)**                                            | ** ** | **2009** | ** ** | **2008** | ** ** |
|--------------------------------------------------------------|------------|----------|------------|----------|------------|
| Actual fuel and purchased power expenditures                 |       | $        | 135.5      |     | $          | 154.1 |   |
| Kansas regulatory adjustments*                               |       | 0.5      |       | (0.7     | )          |
| Missouri fuel adjustment deferral*                           |       | (0.2     | )          | 2.0      |       |
| Missouri fuel adjustment recovery**                          |       | 1.1      |       | —   |       |
| Unrealized gain on derivatives                               |       | (0.4     | )          | —   |       |
| Total fuel and purchased power expense per income  statement |       | $        | 136.5      |     | $          | 155.4 |   |

 

----

*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 nine monthsended September 30, 2009 as compared to the same period in 2008 reflectingtheeffect ofdecreased market demand resulting from milder weather in 2009 as well asdecreased off-system sales.

 

Summarizedin the table below are our estimated cost and volume changes in the componentsof fuel and purchased power expenses for the nine months ended September 30,2009 as compared to the nine months ended September 30, 2008. This tableincorporates all the changes mentioned above. As shown below, the largestimpacts on fuel and purchased power costs were decreased generation by ourgas-fired units and lower gas prices which decreased both generation andpurchased power costs.

 
| **(in millions)**                              | ** ** | **2009** | ** ** |
|------------------------------------------------|------------|----------|------------|
| Coal (cost)                                    |       | $        | 3.7        |   |
| Natural gas (cost)                             |       | (3.5     | )          |
| Purchased power (cost)                         |       | (11.1    | )          |
| Coal generation volume                         |       | (2.3     | )          |
| Natural gas generation volume                  |       | (10.1    | )          |
| Purchased power spot purchase volume           |       | 2.1      |       |
| Natural gas – gain on unwind of positions |       | 2.1      |       |
| Other (including fuel adjustments)             |       | 0.2      |       |
| TOTAL                                          |       | $        | (18.9      | ) |

 

Regulatedoperating expenses for our electric segment increased approximately $0.4million (0.8%) during the nine months ended September 30, 2009 as comparedto the same period in 2008 primarily due to increases of $1.2 million inprofessional services, $0.7 million in other steam power expense, $0.4 millionin customer accounts expense and $0.3 million in general labor costs. Theseincreases were partially offset by decreases of $1.1 million in employee healthcare expense, $0.7 million in injuries and damages expense and $0.5 million inemployee pension expense.

 

Maintenanceand repairs expense increased approximately $5.4 million (28.7%) during thenine months ended September 30, 2009 as compared to 2008 primarily due toincreases of $3.8 million in distribution maintenance costs (including $2.4million of ice storm related amortization), $0.7 million in maintenance andrepairs expense due to the SLCC maintenance outage in the first quarter of2009, $0.7 million in maintenance and repairs expense at the Asbury plant, $0.2million in transmission maintenance expense, $0.1 million in maintenance andrepairs expense at the Iatan plant, $0.1 million in maintenance and repairsexpense at the Energy Center plant and $0.1 million in maintenance and repairsexpense at the State Line plant. These increases were partially offset by a$0.3 million decrease in maintenance and repairs expense at the Riverton plant.

 

Depreciation and amortization expense decreased approximately $2.6million (6.7%) during the nine months ended September 30, 2009 primarilydue to reduced regulatory amortization resulting from the 2008 Missouri ratecase that went into effect on August 23, 2008. Other taxes increasedapproximately $0.8 million during the nine months ended September 30, 2009due to increased property tax reflecting our additions to plant in service andincreased municipal franchise taxes.

 

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***Twelve Months Ended September 30, 2009Compared to Twelve Months Ended September 30, 2008***

 

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

 

For the twelve months ended September 30, 2009, kWh sales to ouron-system customers decreased 2.9% with the associated revenues increasingapproximately $12.8 million (3.2%). Rate changes, primarily the August 2008Missouri rate increase (discussed below), contributed an estimated $25.4million to revenues while continued sales growth contributed an estimated $1.2million. Weather and other related factors decreased revenues an estimated$13.8 million.

 

The decrease in residential and commercial kWh sales during the twelvemonths ended September 30, 2009 was primarily due to the mild weather in2009. The related revenues increased during the twelve months ended September 30,2009 primarily as a result of the 2008 Missouri rate increase and continuedsales growth. Industrial kWh sales decreased 7.1% mainly due to a slowdowncreated by economic uncertainty while the associated revenues decreased only0.6% due to the effects of the Missouri rate increase which partially offsetthe economic conditions**.**On-system wholesale kWh sales and revenues decreasedreflecting the general economic conditions and mild weather.

 

**Off-System Electric Transactions**

 

Thefollowing table sets forth information regarding our off-system sales andrelated expenses for the twelve months ended September 30:

 
| **(in millions)**         | ** ** | **2009** | ** ** | **2008** | ** ** |
|---------------------------|------------|----------|------------|----------|------------|
| EIS revenues              |       | $        | 6.2        |     | $          | 13.1 |   |
| Other revenues            |       | 10.1     |       | 13.6     |       |
| Total off-system revenues |       | 16.3     |       | 26.7     |       |
|                      |       |     |       |     |       |
| EIS expenses              |       | 5.0      |       | 9.3      |       |
| Other expenses            |       | 8.0      |       | 10.3     |       |
| Total off-system expenses |       | 13.0     |       | 19.6     |       |
|                      |       |     |       |     |       |
| Net                       |       | $        | 3.3        |     | $          | 7.1 |   |

 

Revenues and related expenses were less during the twelve months ended September 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 $6.5 million for the twelve monthsended September 30, 2009 as compared to $6.7 million during the same periodin 2008. These revenues are comprised mainly of transmission revenues, latepayment fees and renewable energy credit sales.

 

**Operating Revenue Deductions**

 

During the twelve months ended September 30, 2009, total electricsegment operating expenses decreased approximately $9.7 million (2.6%) comparedwith the same period last year.

 

Totalfuel and purchased power expenses decreased approximately $21.7 million (10.5%)during the twelve months ended September 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 twelve months ended September 30, 2009and 2008.

 

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| **(in millions)**                                            | ** ** | **2009** | ** ** | **2008** | ** ** |
|--------------------------------------------------------------|------------|----------|------------|----------|------------|
| Actual fuel and purchased power expenditures                 |       | $        | 185.5      |     | $          | 205.5 |   |
| Kansas regulatory adjustments*                               |       | 0.6      |       | (0.6     | )          |
| Missouri fuel adjustment deferral*                           |       | (2.0     | )          | 2.0      |       |
| Missouri fuel adjustment recovery**                          |       | 1.1      |       | —   |       |
| Total fuel and purchased power expense per income  statement |       | $        | 185.2      |     | $          | 206.9 |   |

 

----

*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 expense decrease includes theeffect of decreased marketdemand resulting from mild weather in 2009 as well as****theeffects of an extended outage at the Asbury plant lasting from the fourthquarter of 2007 into the first quarter of 2008 during which time we relied onpurchased power and our gas-fired units to replace our coal-fired generation.The decrease in fuel costs also includes theeffect of decreased off-system sales.

 

Summarizedin the table below are our estimated cost and volume changes in the componentsof fuel and purchased power expenses for the twelve months ended September 30,2009 as when compared to the twelve months ended September 30, 2008. Thistable incorporates all the changes mentioned above. As shown below, the largestimpacts on fuel and purchased power costs were lower purchased power andnatural gas prices and decreased generation by our gas-fired units.

 
| **(in millions)**                              | ** ** | **2009** | ** ** |
|------------------------------------------------|------------|----------|------------|
| Coal (cost)                                    |       | $        | 5.2        |   |
| Natural gas (cost)                             |       | (10.7    | )          |
| Purchased power (cost)                         |       | (11.6    | )          |
| Coal generation volume                         |       | 0.4      |       |
| Natural gas generation volume                  |       | (5.4     | )          |
| Purchased power spot purchase volume           |       | (1.2     | )          |
| Natural gas – gain on unwind of positions |       | 2.1      |       |
| Other (including fuel adjustments)             |       | (0.5     | )          |
| TOTAL                                          |       | $        | (21.7      | ) |

 

Regulatedoperating expenses for our electric segment were virtually the same during thetwelve months ended September 30, 2009 as compared to the same period in2008. Increases****of $1.2 million in other steampower expense and $1.6 million in professional services were offset bydecreases of $1.4 million in employee health care expense, $0.8 million inemployee pension expense and $0.7 million in uncollectible accounts.

 

Maintenance and repairs expense increased approximately $6.1 million(22.8%) during the twelve months ended September 30, 2009 as compared to2008 primarily due to increases of $3.8 million in distribution maintenancecosts (including $3.4 million of ice storm related amortization), $0.6 millionin maintenance and repairs expense due to the SLCC maintenance outage in thefirst quarter of 2009, $0.9 million in maintenance and repairs expense at theIatan plant due to an outage in the fourth quarter of 2008, $0.4 million inmaintenance and repairs expense at the Asbury plant and $0.3 million intransmission maintenance costs.

 

Total electric segment operating expenses for the twelve months ended September 30,2008 were reduced due to a $1.2 million gain we recognized in the fourthquarter of 2007 from the sale of our steel unit train set. We recognized nocorresponding gains during the twelve months ended September 30, 2009.

 

Depreciation and amortization expense decreased approximately $3.4million (6.6%) during the twelve months ended September 30, 2009 primarilydue to reduced regulatory amortization resulting from the 2008 Missouri ratecase that went into effect on August 23, 2008. Other taxes increasedapproximately $0.5 million during the twelve months ended September 30,2009 due to increased property tax reflecting our additions to plant in serviceand increased municipal franchise taxes.

 

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***Gas Segment***

 

**Gas Operating Revenues and Sales**

 

**Total Gas Delivered toCustomers**

 
| ** **                 | ** ** | **Three Months Ended** | ** ** | **%**    | ** ** | **Nine Months Ended** | ** ** | **%**    | ** ** | **Twelve Months Ended** | ** ** | **%**      | ** ** |
|----------------------------|------------|------------------------|------------|----------|------------|-----------------------|------------|----------|------------|-------------------------|------------|------------|------------|
| **bcf sales**              | ** ** | **2009**               | ** ** | **2008** | ** ** | **change**            | ** ** | **2009** | ** ** | **2008**                | ** ** | **change** | ** ** | **2009** | ** ** | **2008** | ** ** | **change** | ** ** |
| Residential                |       | 0.13                   |       | 0.11     |       | 24.6                  | %          | 1.74     |       | 1.96                    |       | (11.5      | )%         | 2.72 |   | 2.93 |   | (7.0 | )% |
| Commercial                 |       | 0.12                   |       | 0.10     |       | 15.4                  |       | 0.84     |       | 0.94                    |       | (10.8      | )          | 1.30 |   | 1.36 |   | (4.6 | ) |
| Industrial*                |       | 0.02                   |       | 0.13     |       | (88.4                 | )          | 0.18     |       | 0.33                    |       | (44.8      | )          | 0.40 |   | 0.38 |   | 7.0 |   |
| Other**                    |       | 0.00                   |       | 0.00     |       | (34.1                 | )          | 0.02     |       | 0.02                    |       | (18.9      | )          | 0.03 |   | 0.03 |   | (8.0 | ) |
| Total  retail sales        |       | 0.27                   |       | 0.34     |       | (22.3                 | )          | 2.78     |       | 3.26                    |       | (14.8      | )          | 4.45 |   | 4.70 |   | (5.2 | ) |
| Transportation  sales      |       | 0.88                   |       | 0.77     |       | 13.9                  |       | 2.96     |       | 2.98                    |       | (0.5       | )          | 4.05 |   | 4.14 |   | (2.3 | ) |
| Total  gas operating sales |       | 1.15                   |       | 1.12     |       | 2.8                   |       | 5.74     |       | 6.24                    |       | (7.9       | )          | 8.50 |   | 8.84 |   | (3.8 | ) |

 

----

**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** | ** ** | ** ** | ** ** | **Nine Months Ended** | ** ** | ** ** | ** ** | **Twelve Months Ended** | ** ** | ** **   | ** ** |
|---------------------------------------------------|------------|------------------------|------------|------------|------------|-----------------------|------------|------------|------------|-------------------------|------------|--------------|------------|
| **($ in millions)**                          | ** ** | **2009**               | ** ** | **2008**   | ** ** | **% change**          | ** ** | **2009**   | ** ** | **2008**                | ** ** | **% change** | ** ** | **2009** | ** ** | **2008** | ** ** | **% change** | ** ** |
| Residential                                       |       | $                      | 2.5        |       | $          | 2.6                   |       | (3.7       | )%         | $                       | 25.5       |         | $          | 25.7 |   | (0.9 | )% | $ | 39.4 |   | $ | 37.8 |   | 4.4 | % |
| Commercial                                        |       | 1.5                    |       | 1.7        |       | (10.3                 | )          | 11.0       |       | 11.3                    |       | (2.6         | )          | 17.1 |   | 16.2 |   | 5.7 |   |
| Industrial*                                       |       | 0.2                    |       | 1.2        |       | (85.5                 | )          | 1.8        |       | 3.0                     |       | (40.6        | )          | 3.9 |   | 3.4 |   | 13.7 |   |
| Other**                                           |       | 0.0                    |       | 0.0        |       | (36.3                 | )          | 0.3        |       | 0.3                     |       | (8.7         | )          | 0.4 |   | 0.4 |   | 3.4 |   |
| Total  retail revenues                            |       | $                      | 4.2        |       | $          | 5.5                   |       | (23.8      | )          | $                       | 38.6       |         | $          | 40.3 |   | (4.4 | ) | $ | 60.8 |   | $ | 57.8 |   | 5.3 |   |
| Other  revenues                                   |       | 0.0                    |       | 0.0        |       | (3.5                  | )          | 0.1        |       | 0.2                     |       | (0.6         | )          | 0.2 |   | 0.2 |   | 2.0 |   |
| Transportation  revenues*                         |       | 0.6                    |       | 0.5        |       | 13.4                  |       | 2.1        |       | 2.0                     |       | 4.5          |       | 2.8 |   | 2.7 |   | 0.8 |   |
| Total  gas operating revenues                     |       | $                      | 4.8        |       | $          | 6.0                   |       | (20.8      | )          | $                       | 40.8       |         | $          | 42.5 |   | (4.0 | ) | $ | 63.8 |   | $ | 60.7 |   | 5.1 |   |
| Cost  of gas sold                                 |       | 2.0                    |       | 3.4        |       | (40.4                 | )          | 25.6       |       | 26.4                    |       | (3.3         | )          | 41.8 |   | 38.0 |   | 10.0 |   |
| Gas  operating revenues over cost of gas in rates |       | $                      | 2.8        |       | $          | 2.6                   |       | 4.5        |       | $                       | 15.2       |         | $          | 16.1 |   | (5.1 | ) | $ | 22.0 |   | $ | 22.7 |   | (3.1 | ) |

 

----

**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.*

 

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

 

**Operating Revenues and bcf Sales**

 

Gas retail sales decreased22.3% during the third quarter of 2009 as compared to 2008 primarily due tocustomer contraction of 1.36%, the suspension of operations by a large volumeindustrial customer and the transfer of a customer from industrial sales totransport. Residential sales increased 24.6% and commercial sales increased15.4% during the third quarter of 2009 as compared to the third quarter of 2008.Industrial sales decreased 88.4% during the third quarter of 2009 as comparedto the same period in 2008 due to the suspension of operations by a largevolume industrial customer in the first quarter of 2009 and the transfermentioned above.

 

During the third quarter of2009, gas segment revenues were approximately $4.8 million as compared to $6.0million in the third quarter of 2008, a decrease of 20.8%. During the thirdquarter of 2009, our PGA revenue (whichrepresents the cost of gas recovered from our customers) wasapproximately $2.0 million as compared to $3.4 million in the third quarter of2008, a decrease of approximately $1.4 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 

 

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provisions of the PGAclause, the difference between actual costs incurred and costs recoveredthrough the application of the PGA are reflected as a regulatory asset orregulatory liability until the balance is recovered from or credited tocustomers. As of September 30, 2009, we had unrecovered purchased gas costsof $0.6 million recorded as a regulatory asset. On October 30, 2009, wefiled a request with the MPSC for a decrease in the PGA for our gas customers.

 

**OperatingRevenue Deductions**

 

Totalother operating expenses were approximately $2.3 million during the thirdquarter of 2009 as compared to $2.6 million in the third quarter of 2008 mainlydue to a decrease of $0.3 million in customer accounts expense. Our gas segmenthad a net loss of $1.0 million for the third quarter of 2009 as compared to anet loss of $1.2 million for the third quarter of 2008, which is not unexpecteddue to the seasonality of the gas segment whose heating season runs from November toMarch of each year.

 

***Nine Months Ended September 30, 2009 Comparedto Nine Months Ended September 30, 2008***

 

**Operating Revenues and bcf Sales**

 

Gas retail sales decreased14.8% during the nine months ended September 30, 2009 as compared to thesame period in 2008 mainly due to mild weather during 2009, customercontraction and the suspension of operations by a large volume industrialcustomer in the first quarter of 2009. Residential and commercial salesdecreased during the nine months ended September 30, 2009 as compared tothe same period in 2008 primarily due to the milder weather and customercontraction. Industrial sales decreased during the nine months ended September 30,2009 as compared to the same period in 2008 mainly due to the suspension ofoperations of a customer mentioned above.

 

During the nine months endedSeptember 30, 2009, gas segment revenues were approximately $40.8 millionas compared to $42.5 million in the nine months ended September 30, 2008,a decrease of 4.0%. This decrease was largely driven by the decrease inindustrial sales. During the nine months ended September 30, 2009, our PGArevenue was approximately $25.6 million as compared to $26.4 million during thenine months ended September 30, 2008, a decrease of approximately $0.8million.

 

**OperatingRevenue Deductions**

 

Totalother operating expenses were $7.8 million for the nine months ended September 30,2009 as compared to $7.7 million for the nine months ended September 30,2008. Our gas segment had a net loss of less than $0.1 million for the ninemonths ended September 30, 2009 as compared to net income of $0.6 millionfor the nine months ended September 30, 2008.

 

***Twelve Months Ended September 30, 2009Compared to Twelve Months Ended September 30, 2008***

 

**Operating Revenues and bcf Sales**

 

Gas retail sales decreased5.2% during the twelve months ended September 30, 2009 mainly due to adecrease in residential and commercial sales as compared to 2008. Industrialsales increased during the twelve months ended September 30, 2009 ascompared to the same period in 2008 due to the transfer of a large volumeindustrial customer from transportation to sales service and the addition of anew large volume industrial customer in the second quarter of 2008.

 

During the twelve monthsended September 30, 2009, gas segment revenues were approximately $63.8million as compared to $60.7 million in the twelve months ended September 30,2008, an increase of 5.1%. This increase was largely driven by the increase inindustrial sales and PGA revenue. During the twelve months ended September 30,2009, our PGA revenue was

 

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approximately $41.8 millionas compared to $38.0 million during the twelve months ended September 30,2008, an increase of approximately $3.8 million.

 

**OperatingRevenue Deductions**

 

Totalother operating expenses were $10.2 million for the twelve months ended September 30,2009 as compared to $10.3 million for the twelve months ended September 30,2008. This decrease was mainly due to a decrease of $0.4 million in customeraccounts expense partially offset by a $0.2 million increase in distributionoperation expense. Our gas segment had net income of $1.1 million for thetwelve months ended September 30, 2009 as compared to $1.5 million for thetwelve months ended September 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 September 30:

 
| ** **        | ** ** | **Three Months Ended** | ** ** | **Nine Months Ended** | ** ** | **Twelve Months Ended** | ** ** |
|-------------------|------------|------------------------|------------|-----------------------|------------|-------------------------|------------|
| **(in millions)** | ** ** | **2009**               | ** ** | **2008**              | ** ** | **2009**                | ** ** | **2008** | ** ** | **2009** | ** ** | **2008** | ** ** |
|              |       |                   |       |                  |       |                    |       |   |   |   |   |   |   |
| Revenues          |       | $                      | 1.4        |                  | $          | 1.4                     |       | $ | 4.1 |   | $ | 3.8 |   | $ | 5.4 |   | $ | 4.7 |   |
| Expenses          |       | 1.1                    |       | 1.1                   |       | 3.1                     |       | 3.0 |   | 4.6 |   | 3.6 |   |
| Net  income*      |       | $                      | 0.3        |                  | $          | 0.3                     |       | $ | 1.0 |   | $ | 0.8 |   | $ | 0.8 |   | $ | 1.1 |   |

 

***Consolidated Company***

 

**Income Taxes**

 

Ourconsolidated provision for income taxes decreased approximately $3.0 millionduring the third quarter of 2009 as compared to the third quarter of 2008primarily due to decreased income. Our consolidated provision for income taxesincreased approximately $1.5 million during the nine months ended September 30,2009 and $7.2 million during the twelve months ended September 30, 2009 ascompared to the same periods in 2008 mainly due to increased income.

 

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

 
| ** **                                                 | ** ** | **Three Months Ended** | ** ** | **Nine Months Ended** | ** ** | **Twelve Months Ended** | ** ** |
|------------------------------------------------------------|------------|------------------------|------------|-----------------------|------------|-------------------------|------------|
| ** **                                                 | ** ** | **2009**               | ** ** | **2008**              | ** ** | **2009**                | ** ** | **2008** | ** ** | **2009** | ** ** | **2008** | ** ** |
| Consolidated  effective federal and state income tax rates |       | 31.7                   | %          | 33.0                  | %          | 33.1                    | %          | 32.3 | % | 33.1 | % | 30.5 | % |

 

Therate for the third quarter of 2009 is lower primarily due to lower income. Therates for the nine month ended and twelve month ended periods are higherprimarily due to lower tax benefits received from cost of plant retirementexpenditures. Our cost of retirement expenditures was unusually high during thetwelve months ended September 30, 2008 due to the ice storms weexperienced in 2007. 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) decreased $0.1 million in the third quarter of 2009 ascompared to 2008 primarily due to the completion in April 2009 of theIatan 1 project and lower AFUDC rates. AFUDC increased $1.4 million during thenine months ended September 30, 2009 and increased $2.9 million during thetwelve months ended September 30, 2009 as compared to the same periods inthe prior year due to higher levels of construction in each period.

 

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

 
| ** **                                    | ** ** | **Interest Charges**     | ** ** |
|-----------------------------------------------|------------|--------------------------|------------|
| ** **                                    | ** ** | **($ in millions)** | ** ** |
| ** **                                    | ** ** | **Third**                | ** ** | **Third** | ** ** | ** ** | ** ** | **9 Months** | ** ** | **9 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       |   | $ | 9.6 |   | 14.1 | % | $ | 31.4 |   | $ | 26.4 |   | 18.8 | % | $ | 41.0 |   | $ | 34.5 |   | 18.8 | % |
| Short-term debt interest                      |       | 0.2                      |       | 0.2 |   | (19.6 | ) | 1.0 |   | 1.1 |   | (9.6 | ) | 1.7 |   | 1.9 |   | (5.5 | ) |
| Note payable to securitization trust interest |       | 1.1                      |       | 1.1 |   | 0.0 |   | 3.2 |   | 3.2 |   | 0.0 |   | 4.3 |   | 4.3 |   | 0.0 |   |
| Iatan 1 carrying charges                      |       | (0.3                     | )          | — |   | — |   | (0.9 | ) | — |   | — |   | (0.9 | ) | — |   | — |   |
| Other interest                                |       | 0.1                      |       | 0.3 |   | (49.3 | ) | 0.5 |   | 0.9 |   | (46.1 | ) | 0.8 |   | 1.1 |   | (34.9 | ) |
| Total interest charges                        |       | $                        | 12.0       |   | $ | 11.2 |   | 7.5 |   | $ | 35.2 |   | $ | 31.6 |   | 11.2 |   | $ | 46.9 |   | $ | 41.8 |   | 12.2 |   |

 

**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 valuechanges and settlement activity of open electric segment derivative contractspurchased prior to September 1, 2008, the effective date of our fueladjustment mechanism, are shown below. The net change in fair value is recordedas accumulated other comprehensive income in the capitalization section of ourbalance sheet and does not affect net income or earnings per share. All ofthese contracts have been designated as cash flow hedges. The unrealized gainsand losses accumulated in other comprehensive income are reclassified to fueland purchased power in the periods in which the hedged transaction is actuallyrealized or no longer qualifies for hedge accounting.

 

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

 
| ** **                                       | ** ** | **Three Months Ended** | ** ** | **Nine Months Ended** | ** ** | **Twelve Months Ended** | ** ** |
|--------------------------------------------------|------------|------------------------|------------|-----------------------|------------|-------------------------|------------|
| **(in millions)**                                | ** ** | **2009**               | ** ** | **2008**              | ** ** | **2009**                | ** ** | **2008** | ** ** | **2009** | ** ** | **2008** | ** ** |
| Natural  gas contracts settled (1)               |       | $                      | 6.0        |                  | $          | (3.7                    | )          | $ | 12.7 |   | $ | (6.3 | ) | $ | 15.1 |   | $ | (6.6 | ) |
| Change  in FMV of open contracts for natural gas |       | $                      | (0.1       | )                     | $          | (34.1                   | )          | $ | (7.6 | ) | $ | (0.2 | ) | $ | (24.7 | ) | $ | 3.4 |   |
| Taxes                                            |       | $                      | (2.2       | )                     | $          | 14.4                    |       | $ | (1.9 | ) | $ | 2.5 |   | $ | 3.7 |   | $ | 1.2 |   |
| Total  change in OCI — net of tax           |       | $                      | 3.7        |                  | $          | (23.4                   | )          | $ | 3.2 |   | $ | (4.0 | ) | $ | (5.9 | ) | $ | (2.0 | ) |

 

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*(1) Reflected in fuel expense.*

 

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**RATE MATTERS**

 

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

 

***Electric Segment***

 

*Missouri*

 

*2009 Rate Case*

 

On October 29, 2009, we filed a request with the MPSC for anannual increase in base rates for our Missouri electric customers in the amountof $68.2 million, or 19.6%. This request is primarily to allow us to recover capitalexpenditures associated with environmental upgrades at Iatan 1 and ourinvestment in new generating units at Iatan 2 and the Plum Point GeneratingStation. The Signatory Parties are currently in discussions about procedures tobe used in this case, including the timing of the consideration and raterecovery of our investments in the three generating facilities and otherexpenditures.

 

*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 accounting guidance for regulated activities, 95% of thedifference between the actual cost of fuel and purchased power and the basecost of fuel and purchased power recovered from our customers is recorded as anadjustment to fuel and purchased power expense with a corresponding regulatoryasset or a regulatory liability. If the actual fuel and purchased power costsare higher or lower than the base fuel and purchased power costs billed tocustomers, 95% of these amounts will be recovered or refunded to our customerswhen the fuel adjustment clause is modified. On April 1, 2009, we filedproposed rate schedules with the MPSC requesting an increase of $1.9 million inrevenues for the under recovered fuel costs recognized for the six month periodended February 28, 2009. This increase in revenue was approved by the MPSCon May 21, 2009, became effective June 1, 2009 and is billed throughour fuel adjustment clause. On October 1, 2009, we filed proposed rateschedules with the MPSC requesting a decrease of $0.8 million in revenues forthe over recovered fuel and purchased power costs recognized for the six monthperiod ended August 31, 2009.

 

The MPSC order in the rate case approved aStipulation and Agreement providing for the recovery of deferred expenses ofapproximately $14.2 million over a five year period for the 2007 ice storms. Inaddition, the MPSC order required the implementation of a two-way tracking

 

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mechanism for recovery of the costs relating to the new MPSC rules oninfrastructure inspection and vegetation management. The mechanism authorizedby the MPSC creates a regulatory liability in any year we spend less than thetarget amount, which has been set at $8.6 million for our Missourijurisdiction, and a regulatory asset if we spend more than the target amount.Any regulatory asset and liability amounts created using the tracking mechanismwill then be netted against each other and taken into 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, briefs were filed and the Cole County Circuit Court heard oralarguments on September 29, 2009.

 

*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 were filed by all parties and oralarguments 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. On September 3,2009, the Jasper County Circuit Court dismissed the petition with prejudice. OnOctober 7, 2009, the OPC appealed the Jasper County Circuit Court decisionto the Missouri Court of Appeals — Southern District.

 

*Kansas*

 

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

 

***Gas Segment***

 

OnJune 5, 2009, we filed a request with the MPSC for an annual increase inbase rates for our Missouri gas customers in the amount of $2.9 million, or4.9%. In this filing, we requested recovery of the ongoing cost of operatingand maintaining our 1,200-mile gas distribution system and a return on equityof 11.3%. Results from this case would likely take effect in the second quarterof 2010.

 

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**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 all generationvoluntarily offered into the EIS market to the market participants to alsoserve 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 NERC approvedbalancing authority to take over balancing authority responsibilities for itsmembers, including us, which is expected to provide operational and economicbenefits for us and our customers. The implementation of the Day-Ahead Marketwill replace the existing EIS market, which to date has, and is expected tocontinue 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 theselection process of a group of projects and regional cost allocation rules basedon projected benefits and allocated costs over a ten year period. The plan willbe balanced 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 large enoughin both scale and geography to provide flexibility to meet SPP members’ andcustomers’ 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 1,000 hourly energy sales sinceMay 16, 2005 to numerous counterparties external to our system forwholesale sales made at market prices above the cost based prices permittedunder the mitigation proposal accepted by the FERC. The refund obligationapplied to certain wholesale power sales made “inside” our service area atmarket based rates, even though consumption of the energy occurred outside ourservice area.

 

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

 

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 filed our triennial market power analysis with the FERC on July 30,2009, concluding there were no material changes to our market position. As aresult, we do not anticipate any changes to our existing market based rateauthority. The FERC’s acceptance of our filing is pending.

 

*Other FERC Activity*

 

OnJune 21, 2007, the FERC issued an Advance Notice of Proposed Rulemaking(ANOPR) on potential reforms to improve operations in organized wholesale powermarkets, such as the SPP RTO in which we participate. On October 16, 2008,the FERC issued its Final Order on Wholesale Competition in Regions withOrganized Electric Markets. The Final Order will affect us as it directlyaffects the SPP RTO. The Final Order addresses four key areas for amending itsregulations in Wholesale Competition for RTOs and Independent System Operators(ISOs): (1) demand response and market pricing during periods of operatingreserve shortage; (2) long-term power contracting; (3) marketmonitoring policies; and (4) the responsiveness of RTOs and ISOs tostakeholders and customers. We 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, arerequired to submit a notification filing if there has been a material change infacts that may affect the basis on which a public utility’s waiver waspremised. The Standards of Conduct generally govern the communications betweenour day to day transmission operations personnel and our day to day wholesalemarketing and sales personnel. We submitted our filing on July 13, 2009 inwhich we believe continuation of our waiver, issued in 1997 and reaffirmed in2004, is appropriate and reasonable. Based on the May 21, 2009 order, itis possible that the FERC will

 

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revokeour waiver which would impact communication between our transmission and wholesalemarketing and sales functions and operations within our organization. As partof our filing, we sought a twelve month extension in order to comply with theStandard of Conduct requirements in the event the FERC determined that revokingour waiver was appropriate. The FERC’s decision on this and other Standard ofConduct waiver filings is pending.

 

**LIQUIDITY AND CAPITALRESOURCES**

 

Weused approximately $117.1 million of cash for capital expenditures during thenine months ended September 30, 2009. Our primary source of cash for theseexpenditures during the nine months ended September 30, 2009 was $106.9million in cash provided by operating activities. As of September 30,2009, our working capital was negative (current liabilities exceeded current assets),primarily due to the reclassification of $70 million of long-term debt toreflect its current maturity and the continued use of short-term debt to fundour construction program. Our current maturities include $20 million due November 1,2009 (which was paid at maturity) and $50 million due April 1, 2010. Weexpect to refinance some or all of the long-term debt and continue to useshort-term debt under our unsecured credit agreements. We also have an equitydistribution program in place which is designed to provide additional fundsfrom the issuance of equity from time to time.

 

**Summaryof Cash Flows (in millions)**

 
| ** **                               | ** ** | **Nine Months Ended September 30,** | ** **  |
|------------------------------------------|------------|------------------------------------------|-------------|
| ** **                               | ** ** | **2009**                                 | ** **  | **2008** | ** ** |
| Cash  provided by/(used in):             |       |                                     |        |   |   |
| Operating  activities                    |       | $                                        |  106.9 |   | $ |  86.8 |   |
| Investing  activities                    |       | (116.5                                   | )           | (162.1 | ) |
| Financing  activities                    |       | 12.8                                     |        | 80.9 |   |
| Net  change in cash and cash equivalents |       | $                                        |  3.2   |   | $ |  5.6 |   |

 

**OperatingActivities**

 

Ournet cash flows provided by continuing operating activities were $106.9 millionduring the nine months ended September 30, 2009 as compared to $86.8million for the nine months ended September 30, 2008. This $20.1 millionincrease was primarily due to changes in the level of fuel, materials andsupplies and increases to net income for non-cash expenses, including non-cashlosses on derivatives settling through our margin accounts. Increases indeferred taxes also positively impacted cash flows.

 

**CapitalRequirements and Investing Activities**

 

Ournet cash flows used in investing activities decreased $45.6 million during thenine months ended September 30, 2009 to $116.5 million as compared to$162.1 million in the nine months ended September 30, 2008. This changeoccurred primarily due to a decrease in capital expenditures. The 2008 capitalexpenditures reflect cash outlays for the December 2007 ice storm. Theseexpenditures were incurred in 2007 but paid in the first quarter of 2008. Inaddition, expenditures for new generation and distribution and transmissionsystem additions are lower this year than last. Partially offsetting thecapital expenditures during the nine months ended September 30, 2009 wereproceeds from the sale of land totaling $0.5 million.

 

A breakdown of the capital expenditures for the nine months ended September 30,2009 is as follows:

 

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| ** **                                                   | ** ** | **Capital  Expenditures**    | ** **  |
|--------------------------------------------------------------|------------|------------------------------|-------------|
| ** **                                                   | ** ** | **Nine  Months Ended**       | ** **  |
| **(in millions)**                                            | ** ** | **September 30,  2009** | ** **  |
| Distribution  and transmission system additions              |       | $                            |  24.9  |   |
| New  Generation — Plum Point Energy Station             |       | 13.3                         |        |
| New  Generation — Iatan 2                               |       | 49.3                         |        |
| Storms                                                       |       | 6.5                          |        |
| Additions  and replacements — electric plant            |       | 25.8                         |        |
| Gas  segment additions and replacements                      |       | 1.5                          |        |
| Transportation                                               |       | 1.3                          |        |
| Other  (including retirements and salvage -net) (1)          |       | (2.8                         | )           |
| **Subtotal**                                                 |       | 119.8                        |        |
| Non-regulated  capital expenditures (primarily fiber optics) |       | 1.0                          |        |
| **Subtotal capital expenditures incurred (2)**               |       | 120.8                        |        |
| Adjusted  for capital expenditures payable (3)               |       | 3.7                          |        |
| **Total cash outlay**                                        |       | $                            |  117.1 |   |

 

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(1) Other includesequity AFUDC of $(4.1) 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 thechange in unpaid capital expenditures since the beginning of the year which isnot reflected in the Investing Activities section of the Statement of CashFlows.

 

100%of our cash requirements for capital expenditures during the third quarter of2009 were satisfied internally from operations (funds provided by operatingactivities less dividends paid).

 

Weestimate that our capital expenditures for the remainder of 2009 will beapproximately $51.8 million and for 2010 will be approximately $110.9 million,excluding AFUDC. We estimate that internally generated funds will provideapproximately 19% of the funds required for the remainder of our budgeted 2009capital expenditures. We intend to utilize a combination of short-term debt,the proceeds of sales of long-term debt and/or common stock (including commonstock sold under our equity distribution agreement discussed below, as well asunder our Employee Stock Purchase Plan, our Dividend Reinvestment and StockPurchase Plan, our 401(k) Plan and our ESOP) to finance additional amountsneeded beyond those provided by operating activities for such capitalexpenditures. We will continue to utilize short-term debt as needed to supportnormal operations or other temporary requirements. For further information seeNote 6 of “Notes to Consolidated Financial Statements (Unaudited).”

 

**FinancingActivities**

 

Ournet cash flows provided by financing activities decreased $68.1 million to$12.8 million in 2009 as compared to $80.9 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.

 

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 amount of up to $60 million from time to time through UBS, as salesagent. On October 22, 2009 we amended the agreement to increase theaggregate offering amount from $60 million to $120 million. We intend to usethe net proceeds from this equity distribution program to repay short-term debtand for general corporate purposes, including to fund our current constructionprogram. During the third quarter of 2009, we issued and sold 1,542,682 sharespursuant to this equity distribution program, at an average price per share of$18.09, resulting in proceeds to us of approximately $26.7 million (afterpayment of approximately $1.2 million in commissions to the sales agent).Through October 5, 2009, in the aggregate, we have issued and sold1,692,290 shares pursuant to the program, resulting in net proceeds to us ofapproximately $29.3 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 may alsosell shares to UBS as principal for UBS’ own account at a price agreed upon atthe time of sale.

 

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

 

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

 

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 September 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 80 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 $10.0 million asof November 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 total capitalizationat the end of each fiscal quarter and our EBITDA (defined as net income plusinterest, taxes, depreciation and amortization) to be at least two times ourinterest 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 September 30, 2009, we are in compliance with theseratios. This credit facility is also subject to cross-default if we default onin excess of $10 million in the aggregate on our other indebtedness. Thisarrangement does not serve to legally restrict the use of our cash in the normalcourse of operations. There were $40.0 million of availability thereunder ofoutstanding borrowings under this agreement at September 30, 2009 and anadditional $4.0 million was used to back up our outstanding commercial paper.

 

Theprincipal amount of all series of first mortgage bonds outstanding at any onetime under the EDE Mortgage is limited by terms of the mortgage to $1 billion.Substantially all of the property, plant and equipment of The Empire DistrictElectric Company (but not its subsidiaries) is subject to the lien of the EDEMortgage.****Restrictions inthe EDE mortgage bond indenture could affect our liquidity. The EDE Mortgagecontains a requirement that for new first mortgage bonds to be issued, our netearnings (as defined in the EDE Mortgage) for any twelve consecutive monthswithin the fifteen months preceding issuance must be two times the annualinterest requirements (as defined in the EDE Mortgage) on all first mortgagebonds then outstanding and on the prospective issue of new first mortgagebonds. Our earnings for the twelve months ended September 30, 2009 would permitus to issue approximately $238.6 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. AtSeptember 30, 2009, we had retired bonds and net property

 

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additionswhich would enable the issuance of at least $628.9 million principal amount ofbonds if the annual interest requirements are met. As of September 30, 2009,we are in compliance with all restrictive covenants of the EDE Mortgage.

 

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

 

**CONTRACTUAL OBLIGATIONS**

 

Our contractual obligationshave not significantly changed at September 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. In addition, during the third quarter, we entered into two railcarleases. The first lease is for 135 railcars for our Asbury plant for ten yearswith payments totaling $6.5 million, of which $0.7 million is due in less thanone year, $1.3 million is due in one to three years, $1.3 million is due inthree to five years and the remaining $3.2 million is due in more than 5 years.The second lease is for 54 railcars which are still being constructed. This isa 15 year lease for our Plum Point plant and payments will be determined uponcompletion of the railcars in the fourth quarter of 2009. We signed anagreement with Southern Star to purchase 1 million Dths of firm gas storageservice capacity for a period of five years beginning in April 2011 forour electric segment. The reservation charge for this storage capacity isapproximately $1.1 million annually.

 

**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 September 30, 2009 our retained earnings balance was $13.9 million,compared to $16.7 million as of September 30, 2008, after paying out $33.1million in dividends during the first nine months of 2009. A reduction of ourdividend per share, partially or in whole, could have an adverse effect on ourcommon stock price. On October 22, 2009, the Board of Directors declared aquarterly dividend

 

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of$0.32 per share on common stock payable December 15, 2009 to holders ofrecord as of December 1, 2009.

 

Our diluted earnings pershare were $0.97 for the nine months ended September 30, 2009 and were$1.17 and $1.09 for the years ended December 31, 2008 and 2007, respectively.Dividends paid per share were $0.96 for the nine months ended September 30,2009 and $1.28 for each of the years ended December 31, 2008 and 2007.

 

UnderKansas corporate law, our Board of Directors may only declare and pay dividendsout of our surplus or, if there is no surplus, out of our net profits for thefiscal year in which the dividend is declared or the preceding fiscal year, orboth. Our surplus, under Kansas law, is equal to our retained earnings plusaccumulated other comprehensive income/(loss), net of income tax.

 

Inaddition, the EDE Mortgage and our Restated Articles contain certain dividendrestrictions. The most restrictive of these is contained in the EDE Mortgage,which provides that we may not declare or pay any dividends (other thandividends payable in shares of our common stock) or make any other distributionon, or purchase (other than with the proceeds of additional common stock financing)any shares of, our common stock if the cumulative aggregate amount thereofafter August 31, 1944 (exclusive of the first quarterly dividend of$98,000 paid after said date) would exceed the sum of $10.75 million and theearned surplus (as defined in the EDE Mortgage) accumulated subsequent to August 31,1944, or the date of succession in the event that another corporation succeedsto our rights and liabilities by a merger or consolidation. On March 11,2008, we amended the EDE Mortgage in order to provide us with more flexibilityto pay dividends to our shareholders by increasing the basket available to paydividends by $10.75 million, as described above. As of September 30, 2009,this restriction did not prevent us from issuing dividends.

 

Inaddition, under certain circumstances, our Junior Subordinated Debentures,8-1/2% Series due 2031, reflected as a note payable to securitizationtrust on our balance sheet, held by Empire District Electric Trust I, anunconsolidated securitization trust subsidiary, may also restrict our abilityto pay dividends on our common stock. These restrictions apply if: (1) wehave knowledge that an event has occurred that would constitute an event ofdefault under the indenture governing these junior subordinated debentures andwe have not taken reasonable steps to cure the event, (2) we are indefault with respect to payment of any obligations under our guarantee relatingto the underlying preferred securities, or (3) we have deferred interestpayments on the Junior Subordinated Debentures, 8-1/2% Series due 2031 orgiven notice of a deferral of interest payments. As of September 30, 2009,there were no such restrictions on our ability to pay dividends.

 

**OFF-BALANCE SHEET ARRANGEMENTS**

 

Wehave no off-balance sheet arrangements that have or are reasonably likely tohave a current or future effect on our financial condition, changes infinancial condition, revenues or expenses, results of operations, liquidity,capital expenditures or capital resources, other than operating leases enteredinto in the normal course of business.

 

**CRITICAL ACCOUNTING POLICIES**

 

*Goodwill.**             *We 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 with accountingguidance, goodwill is required to be tested for impairment on an annual basisor whenever events or circumstances indicate possible impairment. In performingimpairment tests, we utilize valuation techniques which estimate the discountedfuture cash flows of operations. Our procedures include developing a baselinetest and performing sensitivity analysis to calculate a reasonable valuationrange. The sensitivities are derived from altering those assumptions which aresubjective in nature and inherent to a discounted cash flows valuationtechnique. Other qualitative factors and comparisons to industry peers are alsoused to further support the assumptions and ultimately the overall evaluation.A significant qualitative factor considered in our evaluation is the impact ofregulation, including rate regulation and cost recovery for our gas segment.Some of the more significant

 

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quantitativeassumptions included in our tests involve: regulatory rate design and results;the discount rate; the growth rate; capital spending rates and terminal valuecalculations. Risks and uncertainties affecting these assumptions include:  management’s identification of impairmentindicators, changes in business, industry, laws, technology or economic andmarket conditions. While management believes the assumptions utilized in ouranalysis were reasonable, significant adverse developments in the gas segmentin future periods or changes in the assumptions could negatively impactgoodwill impairment considerations, which could adversely impact earnings. Weperformed our annual goodwill impairment test as of November 30, 2008 andconcluded our goodwill was not impaired. This test estimated the fair marketvalue of our gas segment to be 10-15% higher than its carrying value at thattime. We do not believe the fair value of our gas segment declined below thecarrying value during the quarter ended September 30, 2009 and as a resultan interim test for impairment was not performed.

 

See“Item 7 — Managements Discussion and Analysis of Financial Condition andResults of Operations” in our Annual Report Form 10-K for the year ended December 31,2008 for a discussion of our other critical accounting policies. There were nochanges in these policies in the quarter ended September 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 the potentialadverse 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, 72% for 2010, 59% for 2011, 28% 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.

 

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Weare exposed to changes in market prices for natural gas we must purchase to runour combustion turbine generators. Our natural gas procurement program isdesigned to manage our costs to avoid volatile natural gas prices. We enterinto physical forward and financial derivative contracts with counterpartiesrelating to our future natural gas requirements that lock in prices (withrespect to predetermined percentages of our expected future natural gas needs)in an attempt to lessen the volatility in our fuel expenditures and improvepredictability. As of October 30, 2009, 81%, or 0.8 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 September 30, 2009, our natural gas cost would increase byapproximately $0.8 million based on our September 30, 2009 total hedgedpositions for the next twelve months. However, such an increase would beprobable of recovery through fuel adjustment mechanisms.

 

Weattempt to mitigate a portion of our natural gas price risk associated with ourgas segment using physical forward purchase agreements, storage and derivativecontracts. As of October 30, 2009, we have 1.8 million Dths in storage onthe three pipelines that serve our customers. This represents 92% of ourstorage capacity. Our long-term hedgestrategy is to mitigate price volatility for our customers by hedging a minimumof 50% of current year, up to 50% of the second year and up to 20% of thirdyear expected gas usage by the beginning of the ACA year at September 1. However, dueto purchased natural gas cost recovery mechanisms for our retail customers,fluctuations in the cost of natural gas have little effect on income.

 

*CreditRisk*.

 

Inorder to minimize overall credit risk, we maintain credit policies, includingthe evaluation of counterparty financial condition and the use of standardizedagreements that facilitate the netting of cash flows associated with a singlecounterparty. See Note 4 of “Notes to Consolidated Financial Statements(Unaudited)” regarding agreements containing credit risk contingent features.In addition, certain counterparties make available collateral in the form ofcash held as margin deposits as a result of exceeding agreed-upon creditexposure thresholds or may be required to prepay the transaction. Conversely,we are required to post collateral with counterparties at certain thresholds,which is typically the result of changes in commodity prices. Amounts reportedas margin deposit liabilities represent counterparty funds we hold that resultfrom various trading counterparties exceeding agreed-upon credit exposurethresholds. Amounts reported as margin deposit assets represent our funds heldon deposit for our NYMEX contracts with various trading counterparties thatresulted from us exceeding agreed-upon credit limits established by thecounterparties. The following table depicts our margin deposit assets andmargin deposit liabilities at September 30, 2009 and December 31,2008:

 
| **(in millions)**      | ** ** | **September 30, 2009** | ** ** | **December 31, 2008** | ** ** |
|------------------------|------------|-----------------------------|------------|----------------------------|------------|
| Margin  deposit assets |       | $                           | 3.4        |                       | $          | 10.7 |   |
|                        |            |                             |            |                            |            |  |  |

 

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 September 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 |       | $          | 6.0        |   |
| Net  unrealized mark-to-market gains for financial natural gas contracts         |       | (2.0       | )          |
| **Net credit exposure**                                                          | ** ** | **$**      | **4.0**    | ** ** |

 

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The $2.0 million netunrealized mark-to-market gain for financial natural gas contracts is comprisedof $4.3 million of exposure to counterparties of Empire for unrealized lossesand $6.3 million of exposure to Empire of unrealized gains from a singlecounterparty. We are holding no collateral from this counterparty since we arebelow the $10 million mark-to-market collateral threshold in our agreement withthis counterparty. As noted above, we have $3.4 million on deposit for NYMEXcounterparty exposure to Empire. Inaddition, if NYMEX gas prices decreased 25% from their October 30, 2009levels, we would be required to post an additional $2.8 million in collateral.If these prices increased 25%, our collateral requirement would decrease $2.9million and our counterparties would be required to post $2.3 million incollateral with Empire.

 

We sell electricity and gasand provide distribution and transmission services to a diverse group ofcustomers, including residential, commercial and industrial customers. Creditrisk associated with trade accounts receivable from energy customers is limiteddue to the large number of customers. In addition, we enter into contracts withvarious companies in the energy industry for purchases of energy-relatedcommodities, including natural gas in our fuel procurement process.

 

*Interest Rate Risk.*

 

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

 

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

 

**Item 4.  Controls andProcedures**

 

As of the end of the periodcovered by this report, an evaluation was carried out, under the supervisionand with the participation of our management, including our Chief ExecutiveOfficer and Chief Financial Officer, of the effectiveness of the design andoperation of our disclosure controls and procedures (as such term is defined inRule 13a-15(e) of the Securities Exchange Act of 1934). Based uponthat evaluation, the Chief Executive Officer and Chief Financial Officerconcluded that our disclosure controls and procedures were effective as of September 30,2009.

 

There have been no changes in our internal control over financial reportingthat occurred during the third quarter of 2009 that have materially affected,or are reasonably likely to materially affect, our internal control overfinancial reporting.

 

**PART II.      OTHER INFORMATION**

 

**Item 1.  Legal Proceedings**

 

***Platte County Levee Lawsuit***

 

On May 22, 2009, a suitwas filed in the Circuit Court of Platte County Missouri by several individualsand Class Representatives alleging damages to land, structures, equipment anddevastation of Plaintiff crops due to inappropriate management of the leveesystem around Iatan, of which we are 12% owners. No procedural schedule hasbeen established and we are unable to predict the outcome of the law suit.

 

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**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.

 

**Any reduction in our creditratings could materially and adversely affect our business, financial conditionand results of operations.**

 

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

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

 

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*Not rated.

**Insured by a third party insurer.

 

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

 

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

 

**We are exposed to increases incosts and reductions in revenue which we cannot control and which may adverselyaffect our business, financial condition and results of operations.**

 

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

 

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

 

Theprimary drivers of our gas operating revenues in any period are: (1) rateswe can charge our customers, (2) weather, (3) customer growth, (4) thecost of natural gas and interstate pipeline transportation charges and (5) generaleconomic conditions. Because natural gas is heavily used for residentialand commercial heating, the demand for this product depends heavily uponweather patterns throughout our natural gas service territory and a significantamount of our natural gas 

 

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revenues are recognized in the first andfourth quarters related to the heating seasons. Accordingly, our natural gasoperations have historically generated less revenues and income when weatherconditions are warmer in the winter.

 

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

 

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

 

**Financial market disruptions mayincrease financing costs, limit access to the credit markets or causereductions in investment values in our pension plan assets.**

 

The recent general marketdeclines resulting in part from the sub-prime mortgage issues have generallyreduced access to the capital markets and reduced market returns on investments.We estimate our capital expenditures to be $168.9 million in 2009. Although webelieve it is unlikely we will have difficulty accessing the markets for thecapital needed to complete these projects, our financing costs will likely behigher when compared to previous years. The market’s effect on our pension planassets resulted in a negative return of 25.1% in 2008. This decline resulted inincreased funding requirements under the Pension Protection Act of 2006.

 

**We are exposed to factors thatcan increase our fuel and purchased power expenditures, including disruption indeliveries of coal or natural gas, decreased output from our power plants,failure of performance by purchased power counterparties and market risk in ourfuel procurement strategy.**

 

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

 

We depend upon regulardeliveries of coal as fuel for our Riverton, Asbury and Iatan plants, and asfuel for the facility which supplies us with purchased power under our contractwith Westar Energy. Substantially all of this coal comes from mines in thePowder River Basin of Wyoming and is delivered to the plants by train.Production problems in these mines, railroad transportation or congestionproblems, such as those that occurred in 2005 and 2006, or unavailability oftrains could affect delivery cycle times required to maintain plant inventorylevels, causing us to implement coal conservation and supply replacementmeasures to retain adequate reserve inventories at our facilities. Thesemeasures could include some or all of the following:  reducing the output of our coal plants,increasing the utilization of our higher-cost gas-fired generation facilities,purchasing power from other suppliers, adding additional leased trains to oursupply system and purchasing locally mined coal which can be delivered withoutusing the railroads. Such measures could result in increased fuel and purchasedpower expenditures.

 

With the addition of theMissouri fuel adjustment mechanism effective September 1, 2008, we nowhave a fuel cost recovery mechanism in all of our jurisdictions, whichsignificantly 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.

 

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

 

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**We are subject to regulation inthe jurisdictions in which we operate.**

 

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

 

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

 

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

 

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

 

**Operationsrisks may adversely affect our business and financial results.**

 

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

 

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

 

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

 

**We may be unable to recoverincreases in the cost of natural gas from our natural gas utility customers, ormay lose customers as a result of any price increases.**

 

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

 

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**We are subject to environmentallaws and the incurrence of environmental liabilities which may adversely affectour business, financial condition and results of operations.**

 

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

 

**The cost and schedule of constructionprojects may materially change.**

 

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

 

There are risks that actualcosts may exceed budget estimates, delays may occur in obtaining permits andmaterials, suppliers and contractors may not perform as required under theircontracts, there may be inadequate availability, 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 of oneor more of the generation plant co-owners to pay their share of construction,operations and maintenance costs, may occur that may materially affect theschedule, budget, cost and performance of these projects. 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. Costs associated with these projects will also besubject to prudency review by regulators as part of future rate case filings.

 

**Item 5.  Other Information.**

 

For the twelve months ended September 30,2009, our ratio of earnings to fixed charges was 2.15x.  See Exhibit (12) hereto.

 

**Item6.  Exhibits.**

 

(a)                                Exhibits.

 

(10) Amendment No. 1, dated October 22,2009 to the Equity Distribution Agreement dated February 25, 2009 betweenThe Empire District Electric Company and UBS Securities LLC (Incorporated byreference to Exhibit 10.1 to Current Report on Form 8-K dated October 22,2009 and filed October 22, 2009, File No. 1 — 3368).

 

(12) Computation of Ratio of Earnings toFixed Charges.

 

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(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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*****This certificationaccompanies this Report pursuant to Section 906 of the Sarbanes-Oxley Actof 2002 and shall not be deemed filed by the Company for purposes of Section 18or any other provision of the Securities Exchange Act 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 |
|                  |                                      |   |
| November 6, 2009 |                                      |   |

 

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