Table ofContents

 

 

 

**UNITEDSTATES**

**SECURITIESAND EXCHANGE COMMISSION**

**WASHINGTON, D.C. 20549**

 

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**FORM 10-Q**

 

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**(Mark One)**

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

 

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

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

 

**For the transition period from               to                .**

 

**Commission file number: 1-3368**

 

**THE EMPIRE DISTRICT ELECTRIC COMPANY**

(Exact name of registrant as specified in itscharter)

 

| **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 check mark whether the registrant (1) has filed allreports required to be filed by Section 13 or 15(d) of the SecuritiesExchange Act of 1934 during the preceding 12 months (or for such shorter periodthat the registrant was required to file such reports), and (2) has beensubject to such filing requirements 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 markwhether the registrant is a large accelerated filer, an accelerated filer, anon-accelerated filer, or a smaller reporting company. See the definitions of “largeaccelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2of the Exchange Act.

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

 

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

 

As of November 1, 2010, 41,492,632 shares of common stock wereoutstanding.

 

 

 

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Table ofContents

 

**THE EMPIRE DISTRICT ELECTRIC COMPANY**

 

**INDEX**

 
| ** **    | ** **                                                                                  | **PAGE** |
|---------------|---------------------------------------------------------------------------------------------|----------|
|          | Forward  Looking Statements                                                                 | 3        |
|          |                                                                                        |     |
| Part I - | Financial  Information:                                                                     |     |
|          |                                                                                        |     |
| Item 1.       | Financial  Statements:                                                                      |     |
|          |                                                                                        |     |
|          | a. Consolidated Statements of Income                                                        | 4        |
|          |                                                                                        |     |
|          | b. Consolidated Statements of Comprehensive Income                                          | 7        |
|          |                                                                                        |     |
|          | c. Consolidated Balance Sheets                                                              | 8        |
|          |                                                                                        |     |
|          | d. Consolidated Statements of Cash Flows                                                    | 10       |
|          |                                                                                        |     |
|          | e. Notes to Consolidated Financial Statements                                               | 11       |
|          |                                                                                        |     |
| Item 2.       | Management’s  Discussion and Analysis of Financial Condition and Results of Operations | 34       |
|          |                                                                                        |     |
|          | Executive Summary                                                                           | 34       |
|          |                                                                                        |     |
|          | Results of Operations                                                                       | 38       |
|          |                                                                                        |     |
|          | Rate Matters                                                                                | 50       |
|          |                                                                                        |     |
|          | Competition                                                                                 | 54       |
|          |                                                                                        |     |
|          | Liquidity and  Capital Resources                                                            | 57       |
|          |                                                                                        |     |
|          | Contractual  Obligations                                                                    | 61       |
|          |                                                                                        |     |
|          | Dividends                                                                                   | 61       |
|          |                                                                                        |     |
|          | Off-Balance Sheet  Arrangements                                                             | 62       |
|          |                                                                                        |     |
|          | Critical  Accounting Policies                                                               | 62       |
|          |                                                                                        |     |
|          | Recently  Issued Accounting Standards                                                       | 62       |
|          |                                                                                        |     |
| Item 3.       | Quantitative  and Qualitative Disclosures About Market Risk                                 | 63       |
|          |                                                                                        |     |
| Item 4.       | Controls and  Procedures                                                                    | 65       |
|          |                                                                                        |     |
| Part II- | Other Information:                                                                          |     |
|          |                                                                                        |     |
| Item 1.       | Legal Proceedings                                                                           | 65       |
|          |                                                                                        |     |
| Item 1A.      | Risk Factors                                                                                | 65       |
|          |                                                                                        |     |
| Item  2.      | Unregistered  Sales of Equity Securities and Use of Proceeds - (none)                       |     |
|          |                                                                                        |     |
| Item  3.      | Defaults  Upon Senior Securities - (none)                                                   |     |
|          |                                                                                        |     |
| Item 5.       | Other Information                                                                           | 65       |
|          |                                                                                        |     |
| Item 6.       | Exhibits                                                                                    | 65       |
|          |                                                                                        |     |
|          | Signatures                                                                                  | 67       |

 

2

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Table of Contents

 

**FORWARD LOOKING STATEMENTS**

 

Certainmatters discussed in this quarterly report are “forward-looking statements”intended to qualify for the safe harbor from liability established by thePrivate Securities Litigation Reform Act of 1995. Such statements address ormay address future plans, objectives, expectations and events or conditionsconcerning various matters such as capital expenditures, earnings, pension andother costs, competition, litigation, our construction program, our generationplans, our financing plans, potential acquisitions, rate and other regulatorymatters, liquidity and capital resources and accounting matters.Forward-looking statements may contain words like “anticipate”, “believe”, “expect”,“project”, “objective” or similar expressions to identify them asforward-looking statements. Factors that could cause actual results to differmaterially from those currently anticipated in such statements include:

 

·                  weather, business and economic conditions andother factors which may impact sales volumes and customer growth;

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

·                  the cost and availability of purchased powerand fuel, and the results of our activities (such as hedging) to reduce thevolatility of such costs;

·                  volatility in the credit, equity and otherfinancial markets and the resulting impact on our short term debt costs and ourability to issue debt or equity securities, or otherwise secure funds to meetour capital expenditure, dividend and liquidity needs;

·                  the results of prudency and similar reviewsby regulators of costs we incur, including capital expenditures and includingSouthwest Power Pool (SPP) regional transmission organization (RTO) expansioncosts;

·                  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 resulting fromnatural disasters, such as tornados and ice storms;

·                  the periodic revision of our construction andcapital expenditure plans and cost and timing estimates;

·                  legislation;

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

·                  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, includingthe potential consequences of International Financial Reporting Standards beingrequired for U.S. SEC registrants rather than U.S. GAAP;

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

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

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

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

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

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

·                  costs and effects of legal and administrativeproceedings, settlements, investigations and claims;

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

·                  other circumstances affecting anticipatedrates, revenues and costs.

 

Allsuch factors are difficult to predict, contain uncertainties that maymaterially affect actual results, and may be beyond our control. New factorsemerge from time to time and it is not possible for management to predict all suchfactors or to assess the impact of each such factor on us.  Any forward-looking statement speaks only asof the date on which such statement is made, and we do not undertake anyobligation to update any forward-looking statement to reflect events or circumstancesafter the date on which such statement is made.

 

Wecaution you that any forward-looking statements are not guarantees of futureperformance and involve known and unknown risk, uncertainties and other factorswhich may cause our actual results, performance or achievements to differmaterially from the facts, results, performance or achievements we haveanticipated in such forward-looking statements.

 

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Tableof Contents

 

**PART I.  FINANCIAL INFORMATION**

 

**Item 1.  Financial Statements**

 

**THE EMPIRE DISTRICT ELECTRIC COMPANY**

**CONSOLIDATED STATEMENTS OF INCOME(UNAUDITED)**

 
| ** **                                                                    | ** ** | **Three Months Ended**                              | ** ** |
|-------------------------------------------------------------------------------|------------|---------------------------------------------------------------|------------|
| ** **                                                                    | ** ** | **September 30**                                         | ** ** |
| ** **                                                                    | ** ** | **2010**                                                      | ** ** | **2009** | ** ** |
| ** **                                                                    | ** ** | **(000’s except per share amounts)** | ** ** |
| **Operating revenues:**                                                       | ** ** | ** **                                                    |       |   |   |
| Electric                                                                      |       | $                                                             | 146,620    |   | $ | 121,487 |   |
| Gas                                                                           |       | 5,403                                                         |       | 4,795 |   |
| Water                                                                         |       | 508                                                           |       | 474 |   |
| Other                                                                         |       | 1,555                                                         |       | 1,297 |   |
|                                                                          |       | 154,086                                                       |       | 128,053 |   |
| **Operating revenue deductions:**                                             | ** ** | ** **                                                    | ** ** | ** ** | ** ** |
| Fuel and purchased power                                                      |       | 57,286                                                        |       | 48,132 |   |
| Cost of natural gas sold and transported                                      |       | 1,554                                                         |       | 2,033 |   |
| Regulated operating expenses                                                  |       | 20,309                                                        |       | 18,854 |   |
| Other operating expenses                                                      |       | 481                                                           |       | 456 |   |
| Maintenance and repairs                                                       |       | 8,722                                                         |       | 8,206 |   |
| Depreciation and amortization                                                 |       | 14,622                                                        |       | 13,034 |   |
| Provision for income taxes                                                    |       | 11,934                                                        |       | 6,894 |   |
| Other taxes                                                                   |       | 7,305                                                         |       | 6,767 |   |
|                                                                          |       | 122,213                                                       |       | 104,376 |   |
|                                                                          |       |                                                          |       |   |   |
| **Operating income**                                                          |       | 31,873                                                        |       | 23,677 |   |
| **Other income and (deductions):**                                            | ** ** | ** **                                                    | ** ** | ** ** | ** ** |
| Allowance for equity funds used during  construction                          |       | 840                                                           |       | 1,429 |   |
| Interest income                                                               |       | 30                                                            |       | 42 |   |
| Benefit for other income taxes                                                |       | 14                                                            |       | 15 |   |
| Other, net                                                                    |       | (245                                                          | )          | (211 | ) |
|                                                                          |       | 639                                                           |       | 1,275 |   |
| **Interest charges:**                                                         |       |                                                          |       |   |   |
| Long-term debt                                                                |       | 10,757                                                        |       | 10,911 |   |
| Trust preferred securities                                                    |       | —                                                        |       | 1,063 |   |
| Short-term debt                                                               |       | 114                                                           |       | 194 |   |
| Allowance for borrowed funds used during  construction                        |       | (771                                                          | )          | (1,911 | ) |
| Other                                                                         |       | (569                                                          | )          | (134 | ) |
|                                                                          |       | 9,531                                                         |       | 10,123 |   |
| **Net income**                                                                |       | $                                                             | 22,981     |   | $ | 14,829 |   |
| Weighted average number of common shares  outstanding - basic                 |       | 41,404                                                        |       | 34,840 |   |
| Weighted average number of common shares  outstanding - diluted               |       | 41,448                                                        |       | 34,887 |   |
| **Total earnings per weighted  average share of common stock — basic**   | ** ** | **$**                                                         | **0.56**   |   | $ | 0.43 |   |
| **Total earnings per weighted  average share of common stock — diluted** | ** ** | **$**                                                         | **0.55**   |   | $ | 0.43 |   |
| **Dividends per share of common  stock**                                      | ** ** | **$**                                                         | **0.32**   |   | $ | 0.32 |   |

 

*See accompanying Notes to Consolidated Financial Statements.*

 

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**THE EMPIRE DISTRICT ELECTRIC COMPANY**

**CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)**

 
| ** **                                                                              | ** ** | **Nine Months Ended**                               | ** ** |
|-----------------------------------------------------------------------------------------|------------|---------------------------------------------------------------|------------|
| ** **                                                                              | ** ** | **September 30,**                                        | ** ** |
| ** **                                                                              | ** ** | **2010**                                                      | ** ** | **2009** | ** ** |
| ** **                                                                              | ** ** | **(000’s except per share amounts)** | ** ** |
| **Operating revenues:**                                                                 | ** ** | ** **                                                    |       |   |   |
| Electric                                                                                |       | $                                                             | 366,469    |   | $ | 330,498 |   |
| Gas                                                                                     |       | 36,480                                                        |       | 40,800 |   |
| Water                                                                                   |       | 1,377                                                         |       | 1,333 |   |
| Other                                                                                   |       | 4,136                                                         |       | 3,667 |   |
|                                                                                    |       | 408,462                                                       |       | 376,298 |   |
| **Operating revenue deductions:**                                                       |       |                                                          |       |   |   |
| Fuel and purchased power                                                                |       | 152,225                                                       |       | 136,470 |   |
| Cost of natural gas sold and transported                                                |       | 18,929                                                        |       | 25,552 |   |
| Regulated operating expenses                                                            |       | 58,497                                                        |       | 54,431 |   |
| Other operating expenses                                                                |       | 1,448                                                         |       | 1,287 |   |
| Maintenance and repairs                                                                 |       | 26,129                                                        |       | 24,798 |   |
| Depreciation and amortization                                                           |       | 41,394                                                        |       | 38,446 |   |
| Provision for income taxes                                                              |       | 26,263                                                        |       | 16,455 |   |
| Other taxes                                                                             |       | 21,347                                                        |       | 20,500 |   |
|                                                                                    |       | 346,232                                                       |       | 317,939 |   |
| **Operating income**                                                                    |       | 62,230                                                        |       | 58,359 |   |
| **Other income and (deductions):**                                                      | ** ** | ** **                                                    | ** ** | ** ** | ** ** |
| Allowance for equity funds used during  construction                                    |       | 4,493                                                         |       | 4,065 |   |
| Interest income                                                                         |       | 152                                                           |       | 180 |   |
| Provision for other income taxes                                                        |       | (78                                                           | )          | (79 | ) |
| Other, net                                                                              |       | (747                                                          | )          | (177 | ) |
|                                                                                    |       | 3,820                                                         |       | 3,989 |   |
| **Interest charges:**                                                                   |       |                                                          |       |   |   |
| Long-term debt                                                                          |       | 31,325                                                        |       | 31,457 |   |
| Trust preferred securities                                                              |       | 2,090                                                         |       | 3,188 |   |
| Short-term debt                                                                         |       | 604                                                           |       | 981 |   |
| Allowance for borrowed funds used during  construction                                  |       | (5,616                                                        | )          | (6,214 | ) |
| Other                                                                                   |       | (1,289                                                        | )          | (432 | ) |
|                                                                                    |       | 27,114                                                        |       | 28,980 |   |
| **Net income**                                                                          |       | $                                                             | 38,936     |   | $ | 33,368 |   |
| Weighted average number of common shares  outstanding - basic                           |       | 40,220                                                        |       | 34,369 |   |
| Weighted average number of common shares  outstanding - diluted                         |       | 40,253                                                        |       | 34,396 |   |
| **Total earnings per weighted  average share of common stock — basic and diluted** |       | $                                                             | 0.97       |   | $ | 0.97 |   |
| **Dividends per share of common  stock**                                                | ** ** | **$**                                                         | **0.96**   |   | $ | 0.96 |   |

 

*See accompanying Notes to Consolidated Financial Statements.*

 

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**THE EMPIRE DISTRICT ELECTRIC COMPANY**

**CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)**

 
| ** **                                                                              | ** ** | **Twelve Months Ended**                             | ** ** |
|-----------------------------------------------------------------------------------------|------------|---------------------------------------------------------------|------------|
| ** **                                                                              | ** ** | **September 30,**                                        | ** ** |
| ** **                                                                              | ** ** | **2010**                                                      | ** ** | **2009** | ** ** |
| ** **                                                                              | ** ** | **(000’s except per share amounts)** | ** ** |
| **Operating revenues:**                                                                 | ** ** | ** **                                                    |       |   |   |
| Electric                                                                                |       | $                                                             | 469,103    |   | $ | 437,247 |   |
| Gas                                                                                     |       | 52,993                                                        |       | 63,759 |   |
| Water                                                                                   |       | 1,808                                                         |       | 1,754 |   |
| Other                                                                                   |       | 5,427                                                         |       | 4,791 |   |
|                                                                                    |       | 529,331                                                       |       | 507,551 |   |
| **Operating revenue deductions:**                                                       |       |                                                          |       |   |   |
| Fuel and purchased power                                                                |       | 197,783                                                       |       | 185,142 |   |
| Cost of natural gas sold and transported                                                |       | 28,978                                                        |       | 41,770 |   |
| Regulated operating expenses                                                            |       | 77,152                                                        |       | 72,384 |   |
| Other operating expenses                                                                |       | 1,962                                                         |       | 1,870 |   |
| Maintenance and repairs                                                                 |       | 34,343                                                        |       | 33,904 |   |
| Depreciation and amortization                                                           |       | 54,441                                                        |       | 51,132 |   |
| Provision for income taxes                                                              |       | 29,379                                                        |       | 20,632 |   |
| Other taxes                                                                             |       | 26,927                                                        |       | 26,250 |   |
|                                                                                    |       | 450,965                                                       |       | 433,084 |   |
| **Operating income**                                                                    |       | 78,366                                                        |       | 74,467 |   |
| **Other income and (deductions):**                                                      | ** ** | ** **                                                    | ** ** | ** ** | ** ** |
| Allowance for equity funds used during  construction                                    |       | 6,636                                                         |       | 5,689 |   |
| Interest income                                                                         |       | 189                                                           |       | 248 |   |
| Benefit/(provision) for other income taxes                                              |       | (310                                                          | )          | 257 |   |
| Other, net                                                                              |       | (1,030                                                        | )          | (957 | ) |
|                                                                                    |       | 5,485                                                         |       | 5,237 |   |
| **Interest charges:**                                                                   |       |                                                          |       |   |   |
| Long-term debt                                                                          |       | 41,951                                                        |       | 41,023 |   |
| Trust preferred securities                                                              |       | 3,152                                                         |       | 4,250 |   |
| Short-term debt                                                                         |       | 748                                                           |       | 1,749 |   |
| Allowance for borrowed funds used during  construction                                  |       | (7,326                                                        | )          | (8,251 | ) |
| Other                                                                                   |       | (1,537                                                        | )          | (171 | ) |
|                                                                                    |       | 36,988                                                        |       | 38,600 |   |
| **Net income**                                                                          |       | $                                                             | 46,863     |   | $ | 41,104 |   |
| Weighted average number of common shares outstanding  — basic                      |       | 39,300                                                        |       | 34,264 |   |
| Weighted average number of common shares  outstanding — diluted                    |       | 39,329                                                        |       | 34,288 |   |
| **Total earnings per weighted  average share of common stock — basic and diluted** |       | $                                                             | 1.19       |   | $ | 1.20 |   |
| **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,**           | ** ** |
| ** **                                                                                                     | ** ** | **2010**                         | ** ** | **2009** | ** ** |
| ** **                                                                                                     | ** ** | **($-000’s)**               | ** ** |
|                                                                                                           |       |                             |       |   |   |
| **Net income**                                                                                                 |       | $                                | 22,981     |   | $ | 14,829 |   |
| Reclassification adjustments for loss included in  net income or reclassified to regulatory asset or liability |       | 4,864                            |       | 6,015 |   |
| Net change in fair market value of derivative  contracts for period                                            |       | (1,934                           | )          | (90 | ) |
| Income taxes                                                                                                   |       | (1,116                           | )          | (2,258 | ) |
|                                                                                                           |       |                             |       |   |   |
| **Comprehensive income**                                                                                       |       | $                                | 24,795     |   | $ | 18,496 |   |

 
| ** **                                                                                                     | ** ** | **Nine Months Ended** | ** ** |
|----------------------------------------------------------------------------------------------------------------|------------|---------------------------------|------------|
| ** **                                                                                                     | ** ** | **September 30,**          | ** ** |
| ** **                                                                                                     | ** ** | **2010**                        | ** ** | **2009** | ** ** |
| ** **                                                                                                     | ** ** | **($-000’s)**              | ** ** |
| ** **                                                                                                     | ** ** | ** **                      | ** ** |
| **Net income**                                                                                                 |       | $                               | 38,936     |   | $ | 33,368 |   |
| Reclassification adjustments for loss included in  net income or reclassified to regulatory asset or liability |       | 5,814                           |       | 12,679 |   |
| Net change in fair market value of derivative  contracts for period                                            |       | (7,258                          | )          | (7,557 | ) |
| Income taxes                                                                                                   |       | 550                             |       | (1,951 | ) |
|                                                                                                           |       |                            |       |   |   |
| **Comprehensive income**                                                                                       |       | $                               | 38,042     |   | $ | 36,539 |   |

 
| ** **                                                                                                     | ** ** | **Twelve Months Ended** | ** ** |
|----------------------------------------------------------------------------------------------------------------|------------|-----------------------------------|------------|
| ** **                                                                                                     | ** ** | **September 30,**            | ** ** |
| ** **                                                                                                     | ** ** | **2010**                          | ** ** | **2009** | ** ** |
| ** **                                                                                                     | ** ** | **($-000’s)**                | ** ** |
|                                                                                                           |       |                              |       |   |   |
| **Net income**                                                                                                 |       | $                                 | 46,863     |   | $ | 41,104 |   |
| Reclassification adjustments for loss included in  net income or reclassified to regulatory asset or liability |       | 6,703                             |       | 15,058 |   |
| Net change in fair market value of derivative  contracts for period                                            |       | (9,278                            | )          | (24,669 | ) |
| Income taxes                                                                                                   |       | 981                               |       | 3,662 |   |
|                                                                                                           |       |                              |       |   |   |
| **Comprehensive income**                                                                                       |       | $                                 | 45,269     |   | $ | 35,155 |   |

 

*See accompanying Notes to Consolidated Financial Statements***.**

 

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**THE EMPIRE DISTRICT ELECTRIC COMPANY**

**CONSOLIDATEDBALANCE SHEETS (UNAUDITED)**

 
| ** **                                             | ** ** | **September 30, 2010** | ** ** | **December 31, 2009** | ** ** |
|--------------------------------------------------------|------------|----------------------------------|------------|---------------------------------|------------|
| ** **                                             | ** ** | **($-000’s)**               | ** ** |
| **Assets**                                             |       |                             |       |                            |       |
| Plant and property, at  original cost:                 |       |                             |       |                            |       |
| Electric                                               |       | $                                | 1,986,170  |                            | $          | 1,619,949 |   |
| Natural gas                                            |       | 59,467                           |       | 58,180                          |       |
| Water                                                  |       | 11,131                           |       | 10,891                          |       |
| Other                                                  |       | 31,804                           |       | 29,564                          |       |
| Construction work in  progress                         |       | 9,554                            |       | 302,012                         |       |
|                                                   |       | 2,098,126                        |       | 2,020,596                       |       |
| Accumulated depreciation and  amortization             |       | 593,174                          |       | 561,586                         |       |
|                                                   |       | 1,504,952                        |       | 1,459,010                       |       |
|                                                   |       |                             |       |                            |       |
| **Current  assets:**                                   |       |                             |       |                            |       |
| Cash and cash equivalents                              |       | 14,688                           |       | 5,620                           |       |
| Accounts receivable — trade,  net                 |       | 48,363                           |       | 36,136                          |       |
| Accrued unbilled revenues                              |       | 14,209                           |       | 23,717                          |       |
| Accounts receivable — other                       |       | 17,477                           |       | 21,417                          |       |
| Fuel, materials and supplies                           |       | 47,464                           |       | 43,973                          |       |
| Unrealized gain in fair  value of derivative contracts |       | 1                                |       | 2,782                           |       |
| Prepaid expenses and other                             |       | 7,168                            |       | 4,438                           |       |
| Regulatory assets                                      |       | 6,761                            |       | 772                             |       |
|                                                   |       | 156,131                          |       | 138,855                         |       |
|                                                   |       |                             |       |                            |       |
| **Noncurrent  assets and deferred charges:**           | ** ** | ** **                       |       |                            |       |
| Regulatory assets                                      |       | 170,740                          |       | 168,254                         |       |
| Goodwill                                               |       | 39,492                           |       | 39,492                          |       |
| Unamortized debt issuance  costs                       |       | 9,416                            |       | 10,638                          |       |
| Unrealized gain in fair  value of derivative contracts |       | 39                               |       | 2,525                           |       |
| Iatan investment tax credits                           |       | —                           |       | 17,713                          |       |
| Other                                                  |       | 3,837                            |       | 3,359                           |       |
|                                                   |       | 223,524                          |       | 241,981                         |       |
| **Total  Assets**                                      |       | $                                | 1,884,607  |                            | $          | 1,839,846 |   |

 

(Continued)

 

*See accompanying Notes to Consolidated Financial Statements***.**

 

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**THE EMPIRE DISTRICT ELECTRIC COMPANY**

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

** **
| ** **                                                                                         | ** ** | **September 30, 2010** | ** ** | **December 31, 2009** | ** ** |
|----------------------------------------------------------------------------------------------------|------------|----------------------------------|------------|---------------------------------|------------|
| ** **                                                                                         | ** ** | **($-000’s)**               | ** ** |
| **Capitalization  and Liabilities**                                                                |       |                             |       |                            |       |
| Common stock, $1 par value,  41,470,569 and 38,112,280 shares issued and outstanding, respectively |       | $                                | 41,471     |                            | $          | 38,112 |   |
| Capital in excess of par  value                                                                    |       | 608,171                          |       | 551,631                         |       |
| Retained earnings                                                                                  |       | 10,291                           |       | 10,068                          |       |
| Accumulated other  comprehensive income/(loss), net of income tax                                  |       | (555                             | )          | 339                             |       |
| **Total  common stockholders’ equity**                                                        |       | 659,378                          |       | 600,150                         |       |
|                                                                                               |       |                             |       |                            |       |
| **Long-term  debt (net of current portion):**                                                      |       |                             |       |                            |       |
| Note payable to  securitization trust                                                              |       | —                           |       | 50,000                          |       |
| Obligations under capital  lease                                                                   |       | 2,451                            |       | 2,563                           |       |
| First mortgage bonds and  secured debt                                                             |       | 488,724                          |       | 339,643                         |       |
| Unsecured debt                                                                                     |       | 199,482                          |       | 247,950                         |       |
| **Total  long-term debt**                                                                          |       | 690,657                          |       | 640,156                         |       |
| **Total  long-term debt and common stockholders’ equity**                                     |       | 1,350,035                        |       | 1,240,306                       |       |
|                                                                                               |       |                             |       |                            |       |
| **Current  liabilities:**                                                                          |       |                             |       |                            |       |
| Accounts payable and accrued  liabilities                                                          |       | 44,936                           |       | 67,406                          |       |
| Current maturities of  long-term debt                                                              |       | 794                              |       | 51,021                          |       |
| Short-term debt                                                                                    |       | 19,000                           |       | 50,500                          |       |
| Customer deposits                                                                                  |       | 10,732                           |       | 10,394                          |       |
| Interest accrued                                                                                   |       | 12,178                           |       | 5,698                           |       |
| Other current liabilities                                                                          |       | 271                              |       | —                          |       |
| Unrealized loss in fair  value of derivative contracts                                             |       | 1,593                            |       | 4,337                           |       |
| Taxes accrued                                                                                      |       | 5,528                            |       | 3,386                           |       |
|                                                                                               |       | 95,032                           |       | 192,742                         |       |
| **Commitments  and contingencies (Note 7)**                                                        | ** ** | ** **                       |       |                            |       |
| **Noncurrent  liabilities and deferred credits:**                                                  | ** ** | ** **                       |       |                            |       |
| Regulatory liabilities                                                                             |       | 83,942                           |       | 87,533                          |       |
| Deferred income taxes                                                                              |       | 207,648                          |       | 194,315                         |       |
| Unamortized investment tax  credits                                                                |       | 19,690                           |       | 20,125                          |       |
| Pension and other  postretirement benefit obligations                                              |       | 79,786                           |       | 84,240                          |       |
| Unrealized loss in fair  value of derivative contracts                                             |       | 3,564                            |       | 426                             |       |
| Other                                                                                              |       | 44,910                           |       | 20,159                          |       |
| ** **                                                                                         |       | 439,540                          |       | 406,798                         |       |
| **Total  Capitalization and Liabilities**                                                          |       | $                                | 1,884,607  |                            | $          | 1,839,846 |   |

 

*See accompanying Notes to Consolidated Financial Statements.*

 

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**THE EMPIRE DISTRICT ELECTRIC COMPANY**

**CONSOLIDATED STATEMENTS OF CASHFLOWS (UNAUDITED)**

 
| ** **                                                                        | ** ** | **Nine Months Ended** | ** ** |
|-----------------------------------------------------------------------------------|------------|---------------------------------|------------|
| ** **                                                                        | ** ** | **September 30,**          | ** ** |
| ** **                                                                        | ** ** | **2010**                        | ** ** | **2009** | ** ** |
| ** **                                                                        | ** ** | **($-000’s)**              | ** ** |
| **Operating activities:**                                                         | ** ** | ** **                      |       |   |   |
| Net income                                                                        |       | $                               | 38,936     |   | $ | 33,368 |   |
| **Adjustments to reconcile net  income to cash flows from operating activities**: |       |                            |       |   |   |
| Depreciation and amortization                                                     |       | 49,644                          |       | 46,115 |   |
| Pension and other postretirement benefit costs,  net of contribution              |       | (3,927                          | )          | 2,447 |   |
| Deferred income taxes and unamortized investment  tax credit, net                 |       | 24,225                          |       | 11,605 |   |
| Allowance for equity funds used during  construction                              |       | (4,493                          | )          | (4,065 | ) |
| Stock compensation expense                                                        |       | 2,355                           |       | 2,119 |   |
| Non-cash loss on derivatives                                                      |       | 1,853                           |       | 9,495 |   |
| Gain on sale of assets                                                            |       | —                          |       | (457 | ) |
| **Cash flows impacted by changes  in:**                                           |       |                            |       |   |   |
| Accounts receivable and accrued unbilled revenues                                 |       | 160                             |       | 9,652 |   |
| Fuel, materials and supplies                                                      |       | (3,491                          | )          | 3,117 |   |
| Prepaid expenses, other current assets and  deferred charges                      |       | (15,733                         | )          | (6,634 | ) |
| Accounts payable and accrued liabilities                                          |       | (20,976                         | )          | (18,915 | ) |
| Customer deposits, interest and taxes accrued                                     |       | 8,959                           |       | 17,915 |   |
| Other liabilities and other deferred credits                                      |       | (342                            | )          | 1,095 |   |
| SWPA minimum flows payment                                                        |       | 26,564                          |       | — |   |
|                                                                              |       |                            |       |   |   |
| **Net cash provided by operating  activities**                                    |       | 103,734                         |       | 106,857 |   |
| ** **                                                                        | ** ** | ** **                      | ** ** | ** ** | ** ** |
| **Investing activities:**                                                         | ** ** | ** **                      | ** ** | ** ** | ** ** |
| Capital expenditures — regulated                                             |       | (78,695                         | )          | (116,075 | ) |
| Capital expenditures and other investments —  non-regulated                  |       | (2,360                          | )          | (978 | ) |
| Proceeds from the sale of property, plant and  equipment                          |       | —                          |       | 544 |   |
|                                                                              |       |                            |       |   |   |
| **Net cash used in investing  activities**                                        |       | (81,055                         | )          | (116,509 | ) |
|                                                                              |       |                            |       |   |   |
| **Financing activities:**                                                         |       |                            |       |   |   |
| Proceeds from first mortgage bonds, net                                           |       | 149,635                         |       | 75,000 |   |
| Proceeds from issuance of notes payable                                           |       | —                          |       | 1,431 |   |
| Long-term debt issuance costs                                                     |       | (1,733                          | )          | (2,397 | ) |
| Proceeds from issuance of common stock, net of  issuance costs                    |       | 58,139                          |       | 30,420 |   |
| Repayment of first mortgage bonds                                                 |       | (50,000                         | )          | — |   |
| Redemption of trust preferred securities                                          |       | (50,000                         | )          | — |   |
| Redemption of senior notes                                                        |       | (48,304                         | )          | — |   |
| Net short-term debt repayments                                                    |       | (31,500                         | )          | (58,000 | ) |
| Dividends                                                                         |       | (38,712                         | )          | (33,068 | ) |
| Other                                                                             |       | (1,136                          | )          | (580 | ) |
|                                                                              |       |                            |       |   |   |
| **Net cash (used in) provided by  financing activities**                          |       | (13,611                         | )          | 12,806 |   |
|                                                                              |       |                            |       |   |   |
| **Net increase in cash and cash  equivalents**                                    |       | 9,068                           |       | 3,154 |   |
| ** **                                                                        | ** ** | ** **                      | ** ** | ** ** | ** ** |
| **Cash and cash equivalents at  beginning of period**                             |       | 5,620                           |       | 2,754 |   |
|                                                                              |       |                            |       |   |   |
| **Cash and cash equivalents at  end of period**                                   |       | $                               | 14,688     |   | $ | 5,908 |   |

 

*See accompanying Notes to Consolidated Financial Statements.*

 

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**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)**

 

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

 

Weoperate our businesses as three segments: electric, gas and other. The Empire District Electric Company (EDE), aKansas corporation organized in 1909, is an operating public utility engaged inthe generation, purchase, transmission, distribution and sale of electricity inparts of Missouri, Kansas, Oklahoma and Arkansas. As part of our electricsegment, we also provide water service to three towns in Missouri. The EmpireDistrict Gas Company (EDG) is our wholly-owned subsidiary which providesnatural gas distribution to communities in northwest, north central and westcentral Missouri. Our other segment consists of our fiber optics business.

 

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

 

The information furnished reflects all adjustments, consisting only ofnormal recurring adjustments, which are in our opinion necessary to statefairly the results for the interim periods as well as present these periods ona consistent basis with the financial statements for the fiscal year ended December 31,2009, of which there were none.

 

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

 

*Fair Value.***In January 2010, theFASB amended the fair value measurements and disclosures guidance to requireadditional disclosures about fair value measurements. The revised guidancerequires new disclosures about the transfers in and out of Level 1 and 2measurements, including descriptions of the reasons for the transfers.Additionally, the reconciliation of Level 3 measurements now requires separatepresentation of sales, issuances and settlements. This guidance for the Level 1and 2 measurements is effective for periods beginning after December 15,2009. The guidance on the Level 3 measurements will be effective for periodsbeginning after December 15, 2010. As this guidance provides onlydisclosure requirements, the adoption of this standard did not impact ourresults of operations, cash flows or financial positions.

 

*Consolidation.***In June 2009, the FASBamended the accounting guidance for consolidations. This amendment is effectivefor annual periods beginning after November 15, 2009. The amendmentrequires an entity to complete a qualitative analysis when determining who mustconsolidate a variable interest entity (VIE). Additionally, the amendmentrequires additional disclosures, and an ongoing reassessment of who must consolidatea VIE. A controlling financial interest is required for a VIE and this isevidenced by either a voting interest greater than 50% or a risk and rewardmodel that identifies EDE as the primary beneficiary of a VIE.

 

Uponadoption of the guidance, we concluded that the consolidation of the EmpireDistrict Electric Trust I was appropriate and we reflected it in ourconsolidated balance sheets in the first quarter of 2010. Subsequently, on June 28,2010, we redeemed all 2 million outstanding shares of our 8.5% trust preferredsecurities held by the Trust.

 

Wealso evaluated our long-term purchase power agreements to determine if we holda variable interest. This evaluation identified our purchase power agreementwith Plum Point Energy Associates, LLC (PPEA, LLC) for capacity with Plum PointEnergy Station, as a variable interest. For this contract we consideredoperations and maintenance of the power plant to be the most significantactivity. In addition, we do not have control over the operation and maintenanceof the power plant. Additionally, we have not provided debt or equityinvestments in PPEA, LLC, we receive less than the majority of the output ofthe facility under the contract and do not provide any other financial supportthrough liquidity arrangements, guarantees or other commitments other than thepurchase power agreement described in Note 7. Based on the consideration ofthese factors, we do not consider ourselves to be the primary beneficiary ofthis VIE. The adoption of this standard did not have a material impact on ourfinancial statements.

 

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SeeNote 1 under “Notes to Consolidated Financial Statements” in our Annual Reporton Form 10-K for the year ended December 31, 2009 for furtherinformation regarding recently issued accounting standards.

 

**Note 3— Regulatory Matters**

 

TheMissouri Public Service Commission (MPSC) approved a regulatory plan in 2005,allowing construction accounting. Construction accounting, for the purposes ofthis regulatory plan, is specific to Iatan 1 and Iatan 2 and allows us to defercertain charges as regulatory assets. These deferred charges includedepreciation, operations and maintenance and carrying costs related tooperation of the facilities until the facilities are ultimately included in ourrates. The regulatory plan also requires us to continue to defer the fuel andpurchased power expense impacts of Iatan 2, which were approximately $0.3million for the quarter and are recorded in Regulatory Liabilities (Other).KCP&L, the operator of Iatan 2, announced on August 26, 2010, thatIatan 2 had met its in-service criteria on August 26, 2010. In addition,in our recently completed Missouri rate case, construction accounting wasapproved for Plum Point, which met its in-service criteria on August 13,2010. Construction accounting for Plum Point applies only to costs incurredsubsequent to February 28, 2010. All of these deferrals begin at thein-service dates and will be amortized over the life of the plants once theyare included in our rates, which we estimate to be upon completion of ourMissouri rate case filed on September 28, 2010. (See Note 7 of “Notes toConsolidated Financial Statements” for additional details). The following tablesets forth the costs related to construction accounting (in thousands):

 
| **Balances as of September 30, 2010** | ** ** | **Deferred Carrying Charges** | ** ** | **Deferred O&M** | ** ** | **Depreciation** | ** ** | **Total** | ** ** |
|----------------------------------------------------------------|------------|-----------------------------------------|------------|---------------------------|------------|------------------|------------|-----------|------------|
| Iatan 1                                                        |       | $                                       | 2,791      |                      | $          | 1,395            |       | $         | 1,690      |   | $ | 5,876 |   |
| Iatan 2                                                        |       | 490                                     |       | 413                       |       | 274              |       | 1,177     |       |
| Plum Point                                                     |       | 11                                      |       | 26                        |       | 11               |       | 48        |       |
|                                                                |            |                                         |            |                           |            |                  |            |           |            |  |  |  |  |

 

Therehave been a few changes to regulatory assets and liabilities regarding theirrate base inclusion or amortizable lives since December 31, 2009. Thesechanges include the amortization of Iatan 1 construction accounting costseffective September 10, 2010, of approximately $10,000 per month, over thelife of the plant, amortization of vegetation tracker costs in Missouri overfive years, amortization of ice storm costs in Kansas and the write off ofapproximately $1.2 million of tax amortization in the first quarter of 2010 forwhich we estimated rate recovery would no longer be probable. See Note 12 —Income Taxes for additional information.

 

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

 

**Regulatory Assets and Liabilities**

 
| ** **                                                              | ** ** | **September 30, 2010** | ** ** | **December 31, 2009** | ** ** |
|-------------------------------------------------------------------------|------------|----------------------------------|------------|---------------------------------|------------|
| **Regulatory Assets:**                                                  |       |                             |       |                            |       |
| Under recovered purchased gas costs — gas segment,  current        |       | $                                | 172        |                            | $          | 434 |   |
| Under recovered electric fuel and purchased power  costs — current |       | 6,589                            |       | 338                             |       |
| Regulatory assets, current**(1)**                                       |       | $                                | 6,761      |                            | $          | 772 |   |
| Pension and other postretirement benefits**(2)**                        |       | 78,532                           |       | 81,171                          |       |
| Income taxes                                                            |       | 48,686                           |       | 49,230                          |       |
| Ice storm costs**(3)**                                                  |       | 8,808                            |       | 11,673                          |       |
| Unamortized loss on reacquired debt                                     |       | 13,471                           |       | 12,167                          |       |
| Unamortized loss on interest rate derivative                            |       | 1,855                            |       | 2,091                           |       |
| Asbury five-year maintenance                                            |       | 1,060                            |       | 1,401                           |       |
| Deferred construction accounting costs                                  |       | 7,101                            |       | 2,732                           |       |
| Asset retirement obligation                                             |       | 3,377                            |       | 3,264                           |       |
| Under recovered electric fuel and purchased power  costs                |       | —                           |       | 662                             |       |
| Unsettled derivative losses — electric segment                     |       | 2,782                            |       | 335                             |       |
| Customer programs                                                       |       | 1,794                            |       | 1,255                           |       |
| System reliability — vegetation management                         |       | 2,358                            |       | 1,636                           |       |
| Other                                                                   |       | 916                              |       | 637                             |       |
| Regulatory assets, long-term                                            |       | $                                | 170,740    |                            | $          | 168,254 |   |
| **Total**                                                               |       | $                                | 177,501    |                            | $          | 169,026 |   |

 

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| ** **                                                     | ** ** | **September 30, 2010** | ** ** | **December 31, 2009** | ** ** |
|----------------------------------------------------------------|------------|----------------------------------|------------|---------------------------------|------------|
| **Regulatory Liabilities:**                                    |       |                             |       |                            |       |
| Cost of removal                                                |       | $                                | 60,253     |                            | $          | 53,083 |   |
| Income taxes                                                   |       | 12,820                           |       | 20,678                          |       |
| Unamortized gain on interest rate derivative                   |       | 3,923                            |       | 4,051                           |       |
| Pension and other postretirement benefits**(4)**               |       | 5,150                            |       | 6,415                           |       |
| Over recovered electric fuel and purchased power  costs**(5)** |       | 670                              |       | 1,344                           |       |
| Over recovered purchased gas costs — gas segment          |       | 736                              |       | 1,874                           |       |
| Other                                                          |       | 390                              |       | 88                              |       |
| **Total**                                                      |       | $                                | 83,942     |                            | $          | 87,533 |   |

 

----

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

(2) Primarilyreflects regulatory assets resulting from the unfunded portion of pension andOPEB liabilities and regulatory accounting for EDG acquisition costs.Approximately $0.4 million in pension and other postretirement benefit costshave been recognized since January 1, 2010, to reflect the amortization ofthe regulatory assets that were recorded at the time of the EDG acquisition.

(3) Primarilyreflects ice storm costs incurred in 2007 currently being recovered andamortized over a five year period, but also includes deferred wind storm costsof $0.7 million incurred in May 2009, also amortized over a five yearperiod commencing in September 2010.

(4) Includesthe effect of costs incurred that are more or less than those allowed in ratesfor the Missouri (EDE and EDG) and Kansas (EDE) portion of pension costs andthe Missouri EDE portion of other postretirement benefit costs. Since January 1,2010, regulatory liabilities and corresponding expenses have been reduced byapproximately $0.4 million as a result of ratemaking treatment.

(5) Primarilyconsists of Missouri over recovered fuel and purchased power costs for thecurrent accumulation period March 2010 through August 2010.

 

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

 

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

 

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

 

Forthose electric instruments entered into prior to September 1, 2008, werecord unrealized gains/(losses) on the ineffective portion of our gas hedgingactivities in “Fuel and purchased power” under the operating revenue deductionssection of our Statement of Income since all of our gas hedging activities arerelated to stabilizing fuel costs as part of our fuel procurement program andare not speculative activities. Risks and uncertainties affecting thedetermination of fair value include: market conditions in the energy industry, especially the effects ofprice volatility, regulatory and global political environments andrequirements, fair value estimations on longer term contracts, theeffectiveness of the derivative instrument in hedging the change in fair valueof the hedged item, estimating underlying fuel demand and counterparty abilityto perform.

 

Asof September 30, 2010 and December 31, 2009, we have recorded thefollowing assets and liabilities representing the fair value of derivativefinancial instruments, (in thousands):

 

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

 
| **Derivatives not designated as hedging  instruments due to regulatory accounting** | ** ** | ** **                               | ** ** | ** ** | ** ** | ** ** | ** ** |
|-----------------------------------------------------------------------------------------------------------------------------|------------|------------------------------------------|------------|------------|------------|------------|------------|
| Natural gas contracts, gas segment                                                                                          |       | Current  assets                          |       | 1          |       | 410        |       |
|                                                                                                                        |       | Non-current  assets                      |       | 39         |       | —     |       |
|                                                                                                                        |       |                                     |       |       |       |       |       |
| Natural gas contracts, electric segment                                                                                     |       | Current  assets                          |       | —     |       | 139        |       |
|                                                                                                                        |       | Non-current  assets and deferred charges |       | —     |       | 87         |       |
| **Total derivatives assets**                                                                                                | ** ** | ** **                               | ** ** | **$**      | **40**     | ** ** | **$**      | **5,307** | ** ** |
|                                                                                                                             |            |                                          |            |            |            |            |            |  |  |

 
| **LIABILITY DERIVATIVES**          | ** ** | **September30,**                  | ** ** | **December 31,** | ** ** |
|-----------------------------------------|------------|-----------------------------------|------------|-----------------------|------------|
| **Derivatives designated as  hedging**  | ** ** | ** **                        | ** ** | **2010**              | ** ** | **2009** | ** ** |
| **instruments**                         | ** ** | **Balance  Sheet Classification** | ** ** | **Fair  Value**       | ** ** | **Fair  Value** | ** ** |
| Natural gas contracts, electric segment |       | Current  liabilities              |       | $                     | 896        |   | $ | 4,123 |   |
|                                         |            |                                   |            |                       |            |  |  |  |  |

 
| **Derivatives not designated as  hedging   instruments due to regulatory   accounting** | ** ** | ** **                                    | ** ** | ** ** | ** ** | ** ** | ** ** |
|-----------------------------------------------------------------------------------------|------------|-----------------------------------------------|------------|------------|------------|------------|------------|
| Natural gas contracts, gas segment                                                      |       | Current  liabilities                          |       | $          | 671        |       | $          | 214 |   |
|                                                                                    |       | Non-current  liabilities                      |       | 5          |       | —     |       |
|                                                                                    |       |                                          |       |       |       |       |       |
| Natural gas contracts, electric segment                                                 |       | Current  liabilities                          |       | 26         |       | —     |       |
|                                                                                    |       | Non-current  liabilities and deferred credits |       | 3,559      |       | 426        |       |
| **Total derivatives liabilities**                                                       | ** ** | ** **                                    | ** ** | **$**      | **5,157**  | ** ** | **$**      | **4,763** | ** ** |

 

*Electric*

 

A$0.6 million net of tax, unrealized loss representing the fair market value ofour electric segment derivative contracts treated as cash flow hedges andentered into prior to September 1, 2008, is recognized as AccumulatedOther Comprehensive Income in the capitalization section of the balance sheetas of September 30, 2010. The tax effect of $0.3 million on this loss isincluded in deferred taxes. These amounts will be adjusted cumulatively on amonthly basis during the determination periods, beginning October 1, 2010and ending on September 30, 2011. At the end of each determination period,or if cash flow hedge treatment is discontinued, any realized gain or loss forthat period related to the instrument is reclassified to fuel expense and issubject to the fuel adjustment clause. As of September 30, 2010,approximately $0.9 million of unrealized losses are applicable to financialinstruments which will settle within the next twelve months. The unrealizedlosses or gains from new cash flow hedges entered into after September 1,2008, are recorded in regulatory assets or liabilities. This is in accordancewith the Accounting Standards Codification (ASC) guidance on accounting forregulated operations, given that those regulatory assets and liabilities areprobable of recovery through our fuel adjustment mechanism. Unrealized gainsand losses from cash flow hedges existing at September 1, 2008 continue tobe recorded through comprehensive income.

 

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

 
| **Derivatives  in Cash**                       | ** ** | ** **                        | ** ** | **Amount of Gain / (Loss) Reclassed from OCI into Income** | ** ** |
|------------------------------------------------|------------|-----------------------------------|------------|------------------------------------------------------------|------------|
| **Flow  Hedging**                              | ** ** | **Income Statement**              | ** ** | **(Effective portion)**                                    | ** ** |
| **Relationships  -**                           | ** ** | **Classification of Gain**        | ** ** | **Three Months Ended**                           | ** ** | **Nine Months Ended** | ** ** | **Twelve Months Ended** | ** ** |
| **Electric  Segment**                          | ** ** | **/ (Loss) on Derivative**        | ** ** | **2010**                                                   | ** ** | **2009** | ** ** | **2010** | ** ** | **2009** | ** ** | **2010** | ** ** | **2009** | ** ** |
| Commodity contracts                            |       | Fuel  and purchased power expense |       | $                                                          | (4,864     | ) | $ | (6,015 | ) | $ | (5,814 | ) | $ | (12,679 | ) | $ | (6,703 | ) | $ | (15,058 | ) |
|                                           |       |                              |       |                                                       |       |   |   |   |   |   |   |   |   |   |   |
| **Total Effective —****Electric Segment** | ** ** | ** **                        | ** ** | **$**                                                      | **(4,864** | **)** | **$** | **(6,015** | **)** | **$** | **(5,814** | **)** | **$** | **(12,679** | **)** | **$** | **(6,703** | **)** | **$** | **(15,058** | **)** |

 

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| **Derivatives  in Cash**                       | ** ** | ** **                | ** ** | **Amount of Gain / (Loss) Recognized in OCI on Derivative** | ** ** |
|------------------------------------------------|------------|---------------------------|------------|-------------------------------------------------------------|------------|
| **Flow  Hedging**                              | ** ** | **Statement of**          | ** ** | **(Effective portion)**                                     | ** ** |
| **Relationships  -**                           | ** ** | **Comprehensive**         | ** ** | **Three Months Ended**                            | ** ** | **Nine Months Ended** | ** ** | **Twelve Months Ended** | ** ** |
| **Electric  Segment**                          | ** ** | **Income**                | ** ** | **2010**                                                    | ** ** | **2009** | ** ** | **2010** | ** ** | **2009** | ** ** | **2010** | ** ** | **2009** | ** ** |
| Commodity contracts                            |       | Net  change in fair value |       | $                                                           | (1,934     | ) | $ | (90 | ) | $ | (7,258 | ) | $ | (7,557 | ) | $ | (9,278 | ) | $ | (24,669 | ) |
|                                           |       |                      |       |                                                        |       |   |   |   |   |   |   |   |   |   |   |
| **Total Effective —****Electric Segment** | ** ** | ** **                | ** ** | **$**                                                       | **(1,934** | **)** | **$** | **(90** | **)** | **$** | **(7,258** | **)** | **$** | **(7,557** | **)** | **$** | **(9,278** | **)** | **$** | **(24,669** | **)** |

 

Theineffective portion of our hedging activities for the electric segment wasinsignificant for each of the periods ended September 30.

 

Inaccordance with the Missouri fuel adjustment clause discussed above, therecoverable portion of any gain or loss is recorded in a regulatory asset orliability account. The following tables set forth “mark-to-market” pre-taxgains/(losses) from derivatives not designated as hedging instruments for theelectric segment for each of the periods ended September 30, (in thousands):

 
| **Derivatives  Not**                        | ** ** | ** **                       | ** ** | ** **                                              | ** **       |
|---------------------------------------------|------------|----------------------------------|------------|---------------------------------------------------------|------------------|
| **Designated  as Hedging**                  | ** ** | **Balance Sheet **          | ** ** | ** **                                              | ** **       |
| **Instruments  - Due to**                   | ** ** | **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**                   | ** ** | **2010**                                                | ** **       | **2009** | ** ** | **2010** | ** ** | **2009** | ** ** | **2010** | ** ** | **2009** | ** ** |
| Commodity contracts — electric segment |       | Regulatory  (assets)/liabilities |       | $                                                       |  (1,646     | ) | $ | 227 |   | $ | (3,384 | ) | $ | (765 | ) | $ | (3,840 | ) | $ | (2,309 | ) |
|                                        |       |                             |       |                                                    |             |   |   |   |   |   |   |   |   |   |   |
| **Total Electric Segment**                  | ** ** | ** **                       | ** ** | **$**                                                   | ** (1,646** | **)** | **$** | **227** | ** ** | **$** | **(3,384** | **)** | **$** | **(765** | **)** | **$** | **(3,840** | **)** | **$** | **(2,309** | **)** |

 
| **Derivatives  Not**       | ** ** | **Statement of**                  | ** ** | ** **                                       | ** ** |
|----------------------------|------------|-----------------------------------|------------|--------------------------------------------------|------------|
| **Designated  as Hedging** | ** ** | **Operations**                    | ** ** | ** **                                       | ** ** |
| **Instruments  - Due to**  | ** ** | **Classification of**             | ** ** | **Amount of Gain / (Loss) Recognized in Income** | ** ** |
| **Regulatory Accounting**  | ** ** | **Gain / (Loss) on**              | ** ** | **Three Months Ended**                 | ** ** | **Nine Months Ended** | ** ** | **Twelve Months Ended** | ** ** |
| **Electric  Segment(1)**   | ** ** | **Derivative**                    | ** ** | **2010**                                         | ** ** | **2009** | ** ** | **2010** | ** ** | **2009** | ** ** | **2010** | ** ** | **2009** | ** ** |
| Commodity contracts        |       | Fuel  and purchased power expense |       | $                                                | (363       | ) | $ | (1,053 | ) | $ | (760 | ) | $ | (2,180 | ) | $ | (859 | ) | $ | (2,509 | ) |
|                       |       |                              |       |                                             |       |   |   |   |   |   |   |   |   |   |   |
| **Total Electric Segment** | ** ** | ** **                        | ** ** | **$**                                            | **(363**   | **)** | **$** | **(1,053** | **)** | **$** | **(760** | **)** | **$** | **(2,180** | **)** | **$** | **(859** | **)** | **$** | **(2,509** | **)** |

 

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

 

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

 

Asof October 22, 2010, the following volumes and percentage of ouranticipated volume of natural gas usage for our electric operations for theremainder of 2010 and for the next four years are shown below at the followingaverage prices per Dekatherm (Dth).

 

**Dth Hedged**

 
| **Year**       | ** ** | **% Hedged** | ** ** | **Physical** | ** ** | **Financial** | ** ** | **Average Price** | ** ** |
|----------------|------------|-------------------|------------|--------------|------------|---------------|------------|------------------------|------------|
| Remainder 2010 |       | 55                | %          | 650,000      |       | 0             |       | $                      | 6.585      |   |
| 2011           |       | 86                | %          | 3,410,000    |       | 2,000,000     |       | $                      | 5.809      |   |
| 2012           |       | 60                | %          | 2,325,000    |       | 1,420,000     |       | $                      | 6.618      |   |
| 2013           |       | 41                | %          | 2,020,000    |       | 1,440,000     |       | $                      | 6.079      |   |
| 2014           |       | 20                | %          | 460,000      |       | 1,120,000     |       | $                      | 5.607      |   |

 

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Weutilize the following procurement guidelines for our electric segment, generally up to a target of 80% of theexpected gas usage in any one year (except for the current year):

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

 

*Gas*

 

We attempt to mitigate our natural gas price riskfor our gas segment by a combination of (1) injecting natural gas intostorage during the off-heating season months, (2) purchasing physicalforward contracts and (3) purchasing financial derivative contracts. Wetarget to have 95% of our storage capacity full by November 1 for theupcoming winter heating season. As the winter progresses, gas is withdrawn fromstorage to serve our customers. As of September 30, 2010, we had 1.8million Dths in storage on the three pipelines that serve our customers. Thisrepresents 88% of our storage capacity. We have an additional 0.9 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** | ** ** | **Balance Sheet**                | ** ** | ** **                                              | ** ** |
| **as  Hedging Instruments Due** | ** ** | **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**                   | ** ** | **2010**                                                | ** ** | **2009** | ** ** | **2010** | ** ** | **2009** | ** ** | **2010** | ** ** | **2009** | ** ** |
| Commodity contracts             |       | Regulatory  (assets)/liabilities |       | $                                                       | (602       | ) | $ | 592 |   | $ | (781 | ) | $ | (1,170 | ) | $ | (283 | ) | $ | (4,502 | ) |
|                            |       |                             |       |                                                    |       |   |   |   |   |   |   |   |   |   |   |
| **Total - Gas Segment**         | ** ** | ** **                       | ** ** | **$**                                                   | **(602**   | **)** | **$** | **592** | ** ** | **$** | **(781** | **)** | **$** | **(1,170** | **)** | **$** | **(283** | **)** | **$** | **(4,502** | **)** |

 

*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, 2010, is $0.5 million for which we have postedno collateral in the normal course of business. If the credit-risk-relatedcontingent features underlying these agreements were triggered on September 30, 2010, we would have been required to postan additional $0.5 million of collateral with the counterparty.

 

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**Note 5—Fair Value Measurements**

 

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

 

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

 

Thefollowing fair value hierarchy table presents information about our assetsmeasured at fair value using the market value approach on a recurring basis asof September 30, 2010 and December 31, 2009.

** **

**($ in000’s)**

 
| ** **                       | ** ** | ** **                                        | ** ** | **Fair Value Measurements at Reporting Date Using**                                                 | ** ** |
|----------------------------------|------------|---------------------------------------------------|------------|-----------------------------------------------------------------------------------------------------|------------|
| **Description**                  | ** ** | **Assets/(Liabilities)  at Fair Value** | ** ** | **Quoted Prices in  Active Markets for  Identical Assets  (Level 1)** | ** ** | **Significant   Other   Observable  Inputs  (Level 2)** | ** ** | **Significant   Unobservable   Inputs  (Level 3)** | ** ** |
| ** **                       | ** ** | **September 30, 2010**                       | ** ** |
| Commodity contracts liabilities* |       | $                                                 | (5,117     | )                                                                                                   | $          | (5,117 | ) | $ | — |   | $ | — |   |
|                             |       |                                              |       |                                                                                                |       |   |   |   |   |
|                             |       | **December 31, 2009**                        |       |
| Commodity contracts assets*      |       | $                                                 | 544        |                                                                                                | $          | 544 |   | $ | — |   | $ | — |   |

 

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

 

Thefollowing tables present the net fair value on a recurring basis usingsignificant unobservable inputs (Level 3) during the periods ended September 30,2010 and 2009:

 

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

 
| ** **                                                                   | ** ** | **2010**                       | ** ** | **2009**                       | ** ** |
|------------------------------------------------------------------------------|------------|--------------------------------|------------|--------------------------------|------------|
| ** **                                                                   | ** ** | **Derivatives Commodity** | ** ** | **Derivatives Commodity** | ** ** |
| **($ in 000’s)**                                              | ** ** | **Contracts(1)**               | ** ** | **Contracts(1)**               | ** ** |
| Beginning Balance, July 1,                                              |       | $                              | —     |                           | $          | 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(2) (3)                              |       |                           |       | —                         |       |
| Ending Balance, September 30,                                           |       | $                              | —     |                           | $          | 3,237 |   |
| Changes in unrealized gains relating to assets  still held at reporting date |       | $                              | —     |                           | $          | (295 | ) |

 

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(1) Netcommodity contracts at September 30, 2010 and 2009 included zero and $3.2million, respectively, in derivative assets, and no derivative liabilities.

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

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

 

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**Fair Value Measurements Using Significant Unobservable Inputs (Level 3)— 9 Months Ended**

 
| ** **                                                                   | ** ** | **2010**                       | ** ** | **2009**                       | ** ** |
|------------------------------------------------------------------------------|------------|--------------------------------|------------|--------------------------------|------------|
| ** **                                                                   | ** ** | **Derivatives Commodity** | ** ** | **Derivatives Commodity** | ** ** |
| **($ in 000’s)**                                              | ** ** | **Contracts(1)**               | ** ** | **Contracts(1)**               | ** ** |
| Beginning Balance, January 1,                                           |       | $                              | —     |                           | $          | 6,208 |   |
| Total gains or (losses) (realized/unrealized)                                |       |                           |       |                           |       |
| Included in earnings (or changes in net assets)                              |       | —                         |       | —                         |       |
| Included in comprehensive income                                             |       |                           |       | (1,738                         | )          |
| Purchases, issuances, and settlements                                        |       | —                         |       | —                         |       |
| Transfers into and (out of) Level 3(2) (3)                              |       |                           |       | (1,233                         | )          |
| Ending Balance, September 30,                                           |       | $                              | —     |                           | $          | 3,237 |   |
| Changes in unrealized gains relating to assets  still held at reporting date |       | $                              | —     |                           | $          | (1,738 | ) |

 

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(1) Netcommodity contracts at September 30, 2010 and 2009 included zero and $3.2million, respectively, in derivative assets, and no derivative liabilities.

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

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

 

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

 
| ** **                                                                   | ** ** | **2010**                       | ** ** | **2009**                       | ** ** |
|------------------------------------------------------------------------------|------------|--------------------------------|------------|--------------------------------|------------|
| ** **                                                                   | ** ** | **Derivatives Commodity** | ** ** | **Derivatives Commodity** | ** ** |
| **($ in 000’s)**                                              | ** ** | **Contracts(1)**               | ** ** | **Contracts(1)**               | ** ** |
| Beginning Balance, October 1,                                           |       | $                              | 3,237      |                           | $          | 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(2) (3)                              |       | (3,237                         | )          | (1,233                         | )          |
| Ending Balance, September 30,                                           |       | $                              | —     |                           | $          | 3,237 |   |
| Changes in unrealized gains relating to assets  still held at reporting date |       | $                              |       |                           | $          | (7,825 | ) |

 

----

(1) Netcommodity contracts at September 30, 2010 and 2009 included zero and $3.2million, respectively, in derivative assets, and no derivative liabilities.

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

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

 

*Long-Term Debt*

 

Thecarrying amount of our total long-term debt exclusive of capital leases at September 30,2010, was $689 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, 2010, orthat will be realizable in the future.

 

**Note 6— Financing**

 

OnAugust 25, 2010, we issued $50 million principal amount of 5.20% firstmortgage bonds due September 1, 2040. The net proceeds (after payment ofexpenses) of approximately $49.1million were used to redeem $48.3 million aggregate principal amount ofour Senior Notes, 7.05% Series due 2022 on August 27, 2010.

 

OnMay 28, 2010, we issued $100 million principal amount of 4.65% firstmortgage bonds due June 1, 2020. The net proceeds (after payment ofexpenses) of approximately $98.8million were used to redeem all 2 million outstanding shares of our 8.5%trust preferred securities totaling 

 

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$50million, on June 28, 2010, and to repay short-term debt which wasincurred, in part, to fund the repayment, at maturity, of our 6.5% firstmortgage bonds due 2010.

 

OnFebruary 25, 2009, we entered into an equity distribution agreement withUBS Securities LLC (UBS). Under the terms of the agreement, as amended, we couldoffer and sell shares of our common stock, par value $1.00 per share, having anaggregate offering amount of up to $120 million from time to time through UBS,as sales agent. We successfully completed this equity distribution programduring the second quarter of 2010 and used the net proceeds to repay short-termdebt and for general corporate purposes, including the funding of ourconstruction program. During the second quarter of 2010, we issued and sold1,192,644 shares of our common stock pursuant to this equity distributionprogram, at an average price per share of $18.60, resulting in net proceeds tous of approximately $21.5 million (after payment of approximately $0.7 millionin commissions to the sales agent). Since inception of the program, in theaggregate, we issued and sold 6,535,216 shares pursuant to the program, at anaverage price per share of $18.36, resulting in net proceeds to us ofapproximately $116.0 million. Sales of the shares pursuant to the equitydistribution agreement were made at market prices or as otherwise agreed withUBS.

 

OnJuly 15, 2005, we entered into a $150 million unsecured revolving creditfacility which was scheduled to terminate on July 15, 2010. On March 14,2006, we entered into the First Amended and Restated Unsecured Credit Agreementwhich amended and restated the $150 million unsecured revolving creditfacility. The principal amount of the credit facility was increased to $226million, with the additional $76 million allocated to support a letter ofcredit issued in connection with our participation in the Plum Point EnergyStation project. This extra $76 million of availability reduced over a fouryear period in line with the amount of construction expenditures we owed forPlum Point Unit 1 and terminated on July 15, 2010.

 

OnJanuary 26, 2010, we entered into the Second Amended and RestatedUnsecured Credit Agreement which amended and restated this facility again. Thisagreement extends the termination date of the revolving credit facility from July 15,2010 to January 26, 2013. In addition, the pricing and fees under thefacility were amended. Interest on borrowings under the facility accrues at arate equal to, at our option, (i) the highest of (A) the bank’s primecommercial rate, (B) the federal funds effective rate plus 0.5% or (C) onemonth LIBOR plus 1.0%, plus a margin or (ii) one month, two month or threemonth LIBOR, in each case, plus a margin. Each margin is based on our currentcredit ratings and the pricing schedule in the facility. As of the date hereof,and based on our current credit ratings, the LIBOR margin under the facilityincreased from 0.80% to 2.70%. A facility fee is payable quarterly on the fullamount of the commitments under the facility and a usage fee is payable on thefull amount of the commitments under the facility for any period in which wehave drawn less than 33% of the total revolving commitments under the facility,in each case based on our current credit ratings. In addition, upon enteringinto the amended and restated facility, we paid an upfront fee to the revolvingcredit banks of $900,000 in the aggregate. The aggregate amount of therevolving commitments remained unchanged at $150 million and there were noother material changes to the terms of the facility.

 

Thefacility is used for working capital, general corporate purposes and to back-upour use of commercial paper. This facility requires our total indebtedness tobe less than 62.5% of our total capitalization at the end of each fiscalquarter and our EBITDA (defined as net income plus interest, taxes,depreciation and amortization) to be at least two times our interest chargesfor the trailing four fiscal quarters at the end of each fiscal quarter.Failure to maintain these ratios will result in an event of default under thecredit facility and will prohibit us from borrowing funds thereunder. As of September 30,2010, we are in compliance with these ratios. This credit facility is alsosubject to cross-default if we default on in excess of $10 million in theaggregate on our other indebtedness. This arrangement does not serve to legallyrestrict the use of our cash in the normal course of operations. There were nooutstanding borrowings under this agreement at September 30, 2010.However, $19.0 million was used to back up our outstanding commercial 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 the guidelinespresented in the ASC on accounting for contingencies. In the opinion ofmanagement, it is not probable, given the company’s defenses, that the ultimateoutcome of these claims and lawsuits will have a material adverse effect uponour financial condition, or results of operations or cash flows.

 

OnMay 22, 2009, a suit was filed in the Circuit Court of Platte CountyMissouri by several individuals and Class Representatives alleging damagesto land, structures, equipment and devastation of Plaintiff crops due toinappropriate management of the levee system around Iatan, of which we are 12%owners. No procedural schedule has been established and we are unable topredict the outcome of the lawsuit.

 

**Coal,Natural Gas and Transportation Contracts**

 

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

 
| **Firm physical gas and transportation contracts**   | ** ** | ** ** | ** ** | ** ** |
|------------------------------------------------------|------------|------------|------------|------------|
| October 1, 2010 through December 31,  2010 |       | $          | 12.7       |       |
| January 1, 2011 through December 31,  2012 |       | 65.4       |       |
| January 1, 2013 through December 31,  2014 |       | 41.7       |       |
| January 1, 2015 and beyond                      |       | 39.2       |       |

 

Wehave coal supply agreements and transportation contracts in place to providefor the delivery of coal to the plants. These contracts are written with ForceMajeure clauses that enable us to reduce tonnages or cease shipments undercertain circumstances or events. These include mechanical or electricalmaintenance items, acts of God, war or insurrection, strikes, weather and otherdisrupting events. This reduces the risk we have for not taking the minimumrequirements of fuel under the contracts. We entered into a contract in thesecond quarter of 2010 to transport coal beginning June 30, 2010, whichreplaced a contract that expired June 29, 2010. The contract term is forsix and one-half years and includes minimum payments totaling approximately$91.9 million. The minimum requirements for our coal and coal transportationcontracts are as follows (in millions):

 
| **Coal and coal transportation contracts**           | ** ** | ** ** | ** ** | ** ** |
|------------------------------------------------------|------------|------------|------------|------------|
| October 1, 2010 through December 31,  2010 |       | $          | 9.2        |       |
| January 1, 2011 through December 31,  2012 |       | 44.7       |       |
| January 1, 2013 through December 31,  2014 |       | 33.5       |       |
| January 1, 2015 and beyond                      |       | 28.1       |       |

 

**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.

 

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

 

Wehave a long-term (30 year) agreement for the purchase of capacity from the PlumPoint Energy Station, a new 665-megawatt, coal-fired generating facility builtby Dynegy near Osceola, Arkansas. The Plum Point Energy Station met itsin-service criteria on August 13, 2010, and we 

 

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beganreceiving purchased power on September 1, 2010. We have the option topurchase an undivided ownership interest in the 50 megawatts covered by thepurchased power agreement in 2015. Commitments under this contract totalapproximately $47.2 million through August 30, 2015.

 

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

 

**New Construction**

 

OnMarch 14, 2006, we entered into contracts to purchase a 50 megawatt,7.52%, undivided interest in the Plum Point Energy Station described above. Theestimated cost is approximately $88.0 million, excluding allowance for fundsused during construction (AFUDC). Our share of the Plum Point costs through September 30,2010, was $86.6 million. The Plum Point Energy Station met its in-servicecriteria on August 13, 2010. Plum Point entered commercial operation on September 1,2010.

 

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 own 12%,or approximately 100 megawatts, of the 850-megawatt unit. KCP&L announcedon August 26, 2010, that Iatan 2 had met its in-service criteria on August 26,2010. Our share of the Iatan 2 construction costs, excluding AFUDC and Empirespecific costs, is expected to be in a range of approximately $229 million to$239 million once all construction costs are final. Our share of the Iatan 2costs through September 30, 2010, was $224.5 million.

 

*Recoveryof construction costs*

 

Wefiled a rate increase request with the MPSC on October 29, 2009 for anannual increase in base rates for our Missouri electric customers in the amountof $68.2 million, or 19.6%. This request was primarily designed to allow us torecover the costs associated with environmental upgrades at Iatan 1 and ourinvestment in new generating units at Iatan 2 and the Plum Point GeneratingStation. As a result of a delay in the Iatan 2 project, however, we agreed tonot seek a permanent increase in that rate case for any costs associated withthe Iatan 2 unit with the exception of that portion of the Iatan common plantneeded to operate Iatan 1. A stipulated agreement was filed on May 12,2010, calling for an annual increase of $46.8 million, provided the Plum PointGenerating Station met its in-service criteria by August 15, 2010. ThePlum Point Generating Station completed its in-service criteria testing on August 12,2010, with the in-service date being August 13, 2010. As a result, the newrates were effective September 10, 2010. The stipulated agreement alsoincludes incremental additional regulatory amortization in the amount of $10million that will be recorded as depreciation expense. As agreed in ourregulatory plan, we will use construction accounting for our Iatan 2 project.Construction accounting allows us to defer certain charges as regulatoryassets, including depreciation, operating expenses and carrying costs, relatedto operation of the facilities until the facilities are ultimately included inour rate base. The regulatory plan also requires us to continue to defer thefuel and purchased power expense impacts of Iatan 2 for the period of timebetween its in-service date and when it is included in our rates. Once theseexpenses are included in our rates, this deferral will also be amortized overthe life of the plant.

 

OnSeptember 28, 2010, we filed a rate increase request with the MPSC for anannual increase in base rates for our Missouri electric customers in the amountof $36.5 million, or 9.2% to 

 

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recoverthe Iatan 2 costs and other cost of service items not included in therecently-completed Missouri rate case.

 

We also filed a request with the Kansas Corporation Commission (KCC) onNovember 4, 2009 for an annual increase in base rates for our Kansaselectric customers in the amount of $5.2 million, or 24.6%. This request wasprimarily to allow us to recover capital expenditures associated with ourinvestment in new generating units at Iatan 2 and the Plum Point GeneratingStation, environmental upgrades at Iatan 1 completed in 2009 and at our Asburyplant completed in 2008, and our Riverton 12 unit that went on line in 2007. Astipulated agreement was filed on May 4, 2010, and approved by the KCC on June 25,2010, calling for a $2.8 million, or 12.4%, increase in base rates effective July 1,2010. We will defer depreciation and operating and maintenance expense on bothPlum Point and Iatan 2 from their respective in-service dates until theeffective date for rates from the next Kansas case, expected to be anabbreviated rate case that will be filed within the next year. These deferralswill be recovered over a 3-5 year period as determined in that next case. Werecorded AFUDC on all Plum Point and Iatan 2 capital expenditures incurredafter January 31, 2010, until their in-service dates.

 

On March 25, 2010, we requested a capital cost recovery rider(CCRR) at the Oklahoma Corporation Commission (OCC). The rider was designed torecover the carrying costs on our capital investment for generation,transmission and distribution assets that have been added to the system sinceour last Oklahoma general rate case (May 2003), as well as investmentsmade on an ongoing basis. As requested, the operation of the CCRR would haveincreased our operating revenue by approximately $3 million, or approximately33% in Oklahoma in a series of three steps to be followed with a general ratecase in 2011. On August 30, 2010, we were granted a two-phase CapitalReliability Rider (CRR) by the OCC. The first phase of the rider was put intoplace for Oklahoma customers for usage on and after September 1, 2010, andresults in an overall annual base revenue increase of approximately $1.5million, or 15.7%. The second phase involves a base revenue increase to be madeeffective after Iatan 2 goes into service, but not before March 1, 2011.The exact level of the phase 2 increase will be determined by the actualin-service cost of Iatan 2. In total, the CRR revenue has been specificallylimited by the OCC to an overall annual revenue increase of $2.6 million, or27.67% increase. We will file a general rate case within six months of thecommercial operation date of Iatan 2 to replace the CRR with permanent rates.

 

OnAugust 19, 2010, we filed a rate increase request with the Arkansas PublicService Commission (APSC) for an annual increase in base rates for our Arkansaselectric customers in the amount of $3.2 million, or 27.3%, to recover costsassociated with environmental upgrades at Iatan 1 and the Asbury Power Plant,and our investment in the new generating units Riverton Unit 12, Iatan 2and the Plum Point Generating Station. We anticipate that any new ratesapproved by the APSC will become effective in the summer of 2011.

 

Theseconstruction costs will be subject to prudency reviews by our regulators.

 

**Leases**

 

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

 

We also currently have short-term operating leasesfor one unit train to meet coal delivery demands, for garage and officefacilities for our electric segment and for six service center properties forour gas segment. In addition, we have capital leases for certain office equipmentand 54 rail cars for the Plum Point generating facility.

 

**Environmental Matters**

 

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

 

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Environmentalrequirements have changed frequently and become more stringent over time. Weexpect this trend to continue. While we are not in a position to accuratelyestimate compliance costs for any new requirements, we expect them to bematerial, although recoverable in rates.

 

***Electric Segment***

 

*Air.*

 

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

 

*Permits*

 

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

 

*SO**2** Emissions*

 

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

 

In2009, our SO2 emissions exceeded the annual allocations.This deficit was covered by our banked allowances. When our SO2 allowance bank is exhausted, currentlyestimated to be early 2012, we will need to purchase additional SO2 allowances or build a Flue GasDesulphurization (FGD) scrubber system at our Asbury Plant. Based on currentand projected SO2 allowance prices and high-level estimated FGDscrubber construction costs (discussed below) and absent other, more stringentregulatory requirements, such as the proposed Clean Air Transport Rule (CATR)and Mercury and Electric Steam Generating Unit (EGU) Maximum Achievable ControlTechnology (MACT) discussed below, it will likely be more economical for us topurchase SO2 allowances than to build a scrubber at theAsbury Plant. If we were to purchase SO2 allowances,we would expect their cost to be fully recoverable in our rates.

 

*NO*x* Emissions*

 

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

 

Ozone,also called ground level smog, is formed by the mixing of NOx and Volatile Organic Compounds in the presenceof sunlight. On January 6, 2010, the EPA proposed to lower the primary NationalAmbient Air Quality Standard (NAAQS) for ozone designed to protect publichealth and to set a secondary NAAQS for ozone designed to protect sensitivevegetation and ecosystems. The EPA is expected to issue final standards by the endof 2010. Once final standards are set, states will be required to develop StateImplementation Plans (SIPs) which reflect these standards.

 

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*CleanAir Interstate Rule (CAIR) and Clean Air Transport Rule (CATR)*

 

In2005, the EPA promulgated CAIR under the CAA. CAIR generally calls forfossil-fueled power plants greater than 25 megawatts to reduce emission levelsof SO2 and NOx in 28 states,including Missouri, where our Asbury, Energy Center, State Line and Iatan UnitsNo. 1 and No. 2 are located and Arkansas where the Plum Point EnergyStation is located. Kansas was not included in CAIR and our Riverton Plant wasnot affected.

 

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

 

TheCAIR requires covered states (including Missouri and Arkansas) to develop SIPsto comply with specific NOx and SO2 state-wide annual budgets. Missouri andArkansas have approved SIPs and, based on these SIPs, we believe we will haveexcess NOx allowances for 2010 which will be banked forfuture use. However, SO2 allowances must be utilized at a 2:1 ratio forour Missouri units as compared to our non-CAIR Kansas units beginning in 2010.As a result, based on current SO2 allowance usage projections, we expect toexhaust our banked allowances by early 2012 and, as discussed above, will needto purchase additional SO2 allowances or build a scrubberat our Asbury Plant.

 

Inorder to meet CAIR requirements and as a requirement for the air permit atIatan 2, a Selective Catalytic Reduction system (SCR), FGD scrubber system andbaghouse were installed at our Iatan 1 plant and an SCR was installed at ourAsbury plant in 2008.

 

OnJuly 6, 2010, the EPA published a proposed CAIR replacement rule entitledthe Clean Air Transport Rule (CATR). As proposed, the CATR would includeKansas under the annual and ozone season NOx and the SO2 programs. Missouri would be dropped from theozone season NOx program whileArkansas would remain in the ozone season NOx program. The beginning date of regulation forthe proposed CATR is 2012. The final CATR is expected to be issued by the EPAwithin 12-14 months. The proposed rule requires a 71% reduction in SO2 and a 52% reduction in NOxfrom 2005 levels by 2014. We do not expect significant impacts on ouroperations because of new NOx requirements in CATR. We cannot accurately estimate the cost of anyfinal regulation or predict its precise timing and its impact on our operationsat this time. Compliance plans range from purchasing additional emissionallowances to installing a FGD scrubber at our Asbury facility (see estimatedconstruction costs below) and potential forced retirement or conversion tonatural gas of our coal-fired Riverton assets. We expect compliance costs to berecoverable in our rates.

 

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

 

In2005, the EPA issued the Clean Air Mercury Rule (CAMR) under the CAA. Itset limits on mercury emissions by power plants and created a market-based capand trade system expected to reduce nationwide mercury emissions in two phases.New mercury emission limits for Phase 1 were to go into effect January 1,2010. On February 8, 2008, the U.S. Court of Appeals for the District ofColumbia vacated CAMR. This decision was appealed to the U.S. Supreme Courtwhich denied the appeal on February 23, 2009.

 

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

 

TheEPA issued an Information Collection Request (ICR) for national emission standardsfor HAPs, including mercury, for coal and oil-fired electric steam generatingunits on December 24, 2009. This ICR included our Iatan, Asbury andRiverton plants. We completed the ICR for Asbury and Riverton and submittedthem to the EPA on March 31, 2010. KCP&L completed and submitted theIatan ICR. The EPA ICR is a prelude to development of regulations under Section 112(r) ofthe CAA maximum achievable emission standards for the control of the emissionof HAPs, including mercury. The EPA is under a court order to issue a proposedEGU MACT regulation by March 16, 2011 and to finalize that regulation by November 16,2011. Absent a successful legal challenge or changes to applicable legislation,we expect EGU MACT regulation to ultimately require a scrubber,

 

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baghouseand powder activated carbon injection system to be added to our Asbury facilityat a cost ranging from $120 million to $180 million and will force retirementof our Riverton coal-fired assets or conversion to natural gas. We expectcompliance costs to be recoverable in our rates.

 

*CO**2** Emissions*

 

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

 

OnSeptember 22, 2009, the EPA issued the final Mandatory Reporting ofGreenhouse Gases Rule under the CAA which requires power generating andcertain other facilities, including EDG that equal or exceed an emissionthreshold of 25,000 metric tons of CO2e to report GHGs to the EPA annually. The firstrecord keeping year is 2010 with initial reporting due in March 2011. Wewill report our GHG emissions as required to the EPA in 2011 for EDE. EDG isnot required to submit its GHG emissions until 2012.

 

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

 

Litigationaimed at controlling GHG emissions has also increased. For example, recentlythe U.S. Court of Appeals for the Second Circuit has ruled that certain publicand private parties can pursue claims that GHG emissions constitute a publicnuisance and can seek to recover alleged related damages. In August 2010,a petition for certiorari was filed by the defendants seeking review of thedecision by the U.S. Supreme Court. In contrast, in May 2010, the fullU.S. Court of Appeals for the Fifth Circuit took action which left standing thelower court’s dismissal of a nuisance claim similar to those upheld by theSecond Circuit.

 

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

 

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

 

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

 

***Water Discharges***

 

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

 

TheRiverton Plant is affected by regulations for Cooling Water Intake Structuresissued by the EPA under the CWA Section 316(b) Phase II. Theregulations became final on February 16,

 

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2004.In accordance with these regulations, we submit sampling and summary reports tothe Kansas Department of Health and Environment (KDHE) which indicate that theeffect of the cooling water intake structure on Empire Lake’s aquatic life isinsignificant. In 2007 the United States Court of Appeals for the SecondCircuit remanded key sections of these CWA regulations to the EPA. As a result,the EPA suspended the regulations and is expected to revise and re-propose theregulations by February 2011. Under the initial regulations, we did notexpect costs associated with compliance to be material. We will reassess costsafter the proposed revised rules are published.

 

*AshPonds.*

 

Weown and maintain coal ash ponds located at our Riverton and Asbury PowerPlants. Additionally, we own a 12 percent interest in a coal ash pond at theIatan Generating Station. The EPA has announced its intention to revise itswastewater effluent limitation guidelines under the CWA for coal-fired powerplants before 2012. Once the new guidelines are issued, the EPA and stateswould incorporate the new standards into wastewater discharge permits,including permits for coal ash ponds. We do not have sufficient information regardingthe future wastewater effluent discharge guidelines at this time to estimateadditional costs that any new standards would impose on our operations. In April andMay 2009, we received Information Collection Requests from the EPAregarding our ash ponds, and have responded to such requests. All of the ashponds are compliant with existing state and federal regulations.

 

OnJune 21, 2010, the EPA published in the Federal Register, its proposed newregulation pursuant to the Federal Resource Conservation and Recovery Act(RCRA) governing the management and storage of Coal Combustion Residuals (CCR).In the proposal the EPA presents two options: (1) regulation of CCR underRCRA subtitle C as a hazardous waste and (2) regulation of CCR under RCRAsubtitle D as a non-hazardous waste. The EPA will accept comments until November 19,2010. It is anticipated that the final regulation will be published in 2011. Weexpect compliance with the final version of either proposal to result in theneed to construct a new landfill and the conversion of existing ash handlingfrom a wet to a dry system(s). We have developed a working preliminaryestimated cost of $15 million to comply with either proposal or combination. Weexpect these costs to be recoverable in our rates. This is a working estimateand we expect the total will change as the CCR rule and designrequirements reach final forms.

 

OnSeptember 23, 2010, representatives from GEI Consultants, on behalf of theEPA, conducted an on-site inspection of our coal ash landfill at Riverton. Theconsultants performed a visual inspection of the landfill to assess thestructural integrity of the berms surrounding the landfill, requesteddocumentation related to construction of the landfill, and reviewed recentlycompleted engineering evaluations of the landfill and its structural integrity.A report has yet to be issued.

 

***Renewable Energy***

 

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

 

OnNovember 4, 2008, Missouri voters approved the Clean Energy Initiative(Proposition C). This initiative requires Empire and other investor-ownedutilities in Missouri to generate or purchase electricity from renewable energysources, such as solar, wind, biomass and hydro power, at the rate of at least2% of retail sales by 2011, increasing to at least 15% by 2021. Two percent ofthis amount must be solar. We believe we are exempted from this requirement. InJuly 2010, the MPSC submitted to the Missouri secretary of state’s officeits rule for the renewable energy mandate. We are awaiting action from theMissouri secretary of state but believe we are in compliance with the law.Kansas established a renewable portfolio standard (RPS) in May 2009. Itsfinal rulemaking is

 

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expectedto be released some time in late 2010. In addition, there are several proposalscurrently before the U.S. Congress to adopt a nationwide RPS.

 

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

 

***Gas Segment***

 

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

 

**Note 8 — Retirement Benefits**

 

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

 
| ** **                                 | ** ** | **Three months ended September 30,** | ** ** |
|--------------------------------------------|------------|----------------------------------------------------------|------------|
| ** **                                 | ** ** | **Pension Benefits**                                | ** ** | **SERP** | ** ** | **OPEB** | ** ** |
| ** **                                 | ** ** | **2010**                                                 | ** ** | **2009** | ** ** | **2010** | ** ** | **2009** | ** ** | **2010** | ** ** | **2009** | ** ** |
| Service cost                               |       | $                                                        | 1,119      |   | $ | 1,449 |   | $ | 18 |   | $ | 15 |   | $ | 585 |   | $ | 409 |   |
| Interest cost                              |       | 2,486                                                    |       | 2,478 |   | 37 |   | 37 |   | 1,122 |   | 879 |   |
| Expected return on plan assets             |       | (2,419                                                   | )          | (2,582 | ) | — |   | — |   | (950 | ) | (952 | ) |
| Amortization of prior service cost **(1)** |       | 133                                                      |       | 151 |   | (2 | ) | (2 | ) | (253 | ) | (253 | ) |
| Amortization of net actuarial loss **(1)** |       | 930                                                      |       | 795 |   | 8 |   | 26 |   | 436 |   | 64 |   |
| **Net periodic benefit cost**              | ** ** | **$**                                                    | **2,249**  | ** ** | **$** | **2,291** | ** ** | **$** | **61** | ** ** | **$** | **76** | ** ** | **$** | **940** | ** ** | **$** | **147** | ** ** |

 
| ** **                                 | ** ** | **Nine months ended September 30,** | ** ** |
|--------------------------------------------|------------|---------------------------------------------------------|------------|
| ** **                                 | ** ** | **Pension Benefits**                               | ** ** | **SERP** | ** ** | **OPEB** | ** ** |
| ** **                                 | ** ** | **2010**                                                | ** ** | **2009** | ** ** | **2010** | ** ** | **2009** | ** ** | **2010** | ** ** | **2009** | ** ** |
| Service cost                               |       | $                                                       | 3,665      |   | $ | 3,459 |   | $ | 52 |   | $ | 46 |   | $ | 1,603 |   | $ | 1,372 |   |
| Interest cost                              |       | 7,586                                                   |       | 7,407 |   | 115 |   | 111 |   | 3,247 |   | 2,930 |   |
| Expected return on plan assets             |       | (7,385                                                  | )          | (7,785 | ) | — |   | — |   | (2,883 | ) | (2,882 | ) |
| Amortization of prior service cost **(1)** |       | 399                                                     |       | 453 |   | (6 | ) | (6 | ) | (758 | ) | (758 | ) |
| Amortization of net actuarial loss **(1)** |       | 2,997                                                   |       | 2,387 |   | 72 |   | 77 |   | 1,124 |   | 652 |   |
| **Net periodic benefit cost**              | ** ** | **$**                                                   | **7,262**  | ** ** | **$** | **5,921** | ** ** | **$** | **233** | ** ** | **$** | **228** | ** ** | **$** | **2,333** | ** ** | **$** | **1,314** | ** ** |

 
| ** **                                 | ** ** | **Twelve months ended September 30,** | ** ** |
|--------------------------------------------|------------|-----------------------------------------------------------|------------|
| ** **                                 | ** ** | **Pension Benefits**                                 | ** ** | **SERP** | ** ** | **OPEB** | ** ** |
| ** **                                 | ** ** | **2010**                                                  | ** ** | **2009** | ** ** | **2010** | ** ** | **2009** | ** ** | **2010** | ** ** | **2009** | ** ** |
| Service cost                               |       | $                                                         | 4,818      |   | $ | 4,351 |   | $ | 68 |   | $ | 60 |   | $ | 2,060 |   | $ | 1,785 |   |
| Interest cost                              |       | 10,055                                                    |       | 9,669 |   | 152 |   | 145 |   | 4,224 |   | 3,835 |   |
| Expected return on plan assets             |       | (9,980                                                    | )          | (10,467 | ) | — |   | — |   | (3,843 | ) | (3,820 | ) |
| Amortization of prior service cost **(1)** |       | 550                                                       |       | 639 |   | (8 | ) | (8 | ) | (1,011 | ) | (1,011 | ) |
| Amortization of net actuarial loss **(1)** |       | 3,792                                                     |       | 2,810 |   | 98 |   | 110 |   | 1,341 |   | 780 |   |
| **Net periodic benefit cost**              | ** ** | **$**                                                     | **9,235**  | ** ** | **$** | **7,002** | ** ** | **$** | **310** | ** ** | **$** | **307** | ** ** | **$** | **2,771** | ** ** | **$** | **1,569** | ** ** |

 

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

 

Annualcontributions to our pension plans are at least equal to the minimum fundingrequirements of ERISA. Beginning in 2010, we will also be required to fund atleast our actuarial cost in accordance with our regulatory agreements. On September 14,2010, we made an $8.2 million contribution to our pension plan. We will berequired to make additional contributions totaling

 

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$1.5million during the remainder of 2010 in order to satisfy the minimum fundingrequirements as described in our regulatory agreements. The minimum fundingrequirements for 2011 will be determined based on the results of the actuarialvaluation and the performance of our pension assets during 2010. Our OPEB fundingpolicy is to contribute annually an amount at least equal to the actuarial costof postretirement benefits. Our funding for 2010 will total approximately $3.2million.

 

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

 

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

 

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

 

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

 
| ** **                 | ** ** | **Three Months Ended** | ** ** | **Nine Months Ended** | ** ** | **Twelve Months Ended** | ** ** |
|----------------------------|------------|----------------------------------|------------|---------------------------------|------------|-----------------------------------|------------|
| ** **                 | ** ** | **2010**                         | ** ** | **2009**                        | ** ** | **2010**                          | ** ** | **2009** | ** ** | **2010** | ** ** | **2009** | ** ** |
| **Compensation Expense**   |       | $                                | 556        |                            | $          | 589                               |       | $ | 2,097 |   | $ | 1,837 |   | $ | 2,551 |   | $ | 1,872 |   |
| **Tax Benefit Recognized** |       | 200                              |       | 209                             |       | 754                               |       | 661 |   | 912 |   | 663 |   |
|                            |            |                                  |            |                                 |            |                                   |            |  |  |  |  |  |  |  |  |  |  |  |  |

 

Activityfor our various stock plans for the nine months ended September 30, 2010,is summarized below:

 

**Performance-BasedRestricted Stock Awards**

 

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

 
| ** **                                   | ** ** | **Fair Value of Grants Outstanding at September 30,** | ** ** |
|----------------------------------------------|------------|------------------------------------------------------------------------------------------|------------|
| ** **                                   | ** ** | **2010**                                                                                 | ** ** | **2009** | ** ** |
| **Risk-free interest rate**                  |       | 0.17% to 0.50%                                                                           |       | 0.07% to 1.05% |   |
| **Expected volatility of Empire  stock**     |       | 27.6%                                                                                    |       | 28.9% |   |
| **Expected volatility of peer  group stock** |       | 21.9% to 82.6%                                                                           |       | 21.9% to 80.3% |   |
| **Expected dividend yield on  Empire stock** |       | 6.8%                                                                                     |       | 7.6% |   |
| **Expected forfeiture rates**                |       | 3%                                                                                       |       | 3% |   |
| **Plan cycle**                               |       | 3 years                                                                                  |       | 3 years |   |
| **Fair value percentage**                    |       | 120.0% to 140.0%                                                                         |       | 112.0% to 117.0% |   |
| **Weighted average fair value per  share**   |       | $26.63                                                                                   |       | $22.39 |   |

 

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

 

28

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| ** **                          | ** ** | **2010**           | ** ** | **2009**                       | ** ** |
|-------------------------------------|------------|--------------------|------------|--------------------------------|------------|
| ** **                          | ** ** | **Number**         | ** ** | **Weighted Average**      | ** ** | **Number** | ** ** | **Weighted Average** | ** ** |
| ** **                          | ** ** | **of shares** | ** ** | **Grant Date Price** | ** ** | **of shares** | ** ** | **Grant Date Price** | ** ** |
| **Nonvested at January 1,**    |       | 52,200             |       | $                              | 21.57      |   | 52,300 |   | $ | 22.64 |   |
| **Granted**                         |       | 13,000             |       | $                              | 18.36      |   | 13,500 |   | $ | 18.12 |   |
| **Awarded**                         |       | (15,104            | )          | $                              | 23.81      |   | (12,394 | ) | $ | 22.23 |   |
| **Not Awarded**                     |       | (2,596             | )          |                           |       | (1,206 | ) |   |   |
|                                |       |               |       |                           |       |   |   |   |   |
| **Nonvested at September 30,** |       | 47,500             |       | $                              | 19.86      |   | 52,200 |   | $ | 21.57 |   |

 

AtSeptember 30, 2010, there was $0.4 million of total unrecognizedcompensation cost related to estimated outstanding awards. This cost will berecognized over the outstanding years remaining in the vesting period.

 

**StockOptions**

 

Stockoption grants vest upon satisfaction of service conditions. The cost of theawards is generally recognized over the requisite (explicit) service period.The fair value of the outstanding options was estimated as of September 30,2010 and 2009, under a Black-Scholes methodology. The assumptions used in thevaluations are shown below:

 
| ** **                                  | ** ** | **Fair Value of Grants Outstanding at September 30,** | ** ** |
|---------------------------------------------|------------|------------------------------------------------------------------------------------------|------------|
| ** **                                  | ** ** | **2010**                                                                                 | ** ** | **2009** | ** ** |
| **Risk-free interest rate**                 |       | 0.38% to 1.59%                                                                           |       | 1.01% to 2.64% |   |
| **Expected dividend yield**                 |       | 6.8%                                                                                     |       | 7.6% |   |
| **Expected volatility**                     |       | 24.0%                                                                                    |       | 24.0% |   |
| **Expected life in months**                 |       | 78                                                                                       |       | 78 |   |
| **Market value**                            |       | $20.15                                                                                   |       | $18.09 |   |
| **Weighted average fair value per  option** |       | $1.35                                                                                    |       | $0.82 |   |

 

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

 
| ** **                             | ** ** | **2010**    | ** ** | **2009**                  | ** ** |
|----------------------------------------|------------|-------------|------------|---------------------------|------------|
| ** **                             | ** ** | ** **  | ** ** | **Weighted Average** | ** ** | ** ** | ** ** | **Weighted Average** | ** ** |
| ** **                             | ** ** | **Options** | ** ** | **Exercise Price**   | ** ** | **Options** | ** ** | **Exercise Price** | ** ** |
| **Outstanding at January 1,**     |       | 232,600     |       | $                         | 22.19      |   | 205,600 |   | $ | 22.73 |   |
| **Granted**                            |       | 34,800      |       | $                         | 18.36      |   | 27,000 |   | $ | 18.12 |   |
| **Exercised**                          |       | —      |       |                      |       | — |   |   |   |
| **Outstanding at  September 30,** |       | 267,400     |       | $                         | 21.69      |   | 232,600 |   | $ | 22.19 |   |
| **Exercisable at  September 30,** |       | 149,200     |       | $                         | 23.04      |   | 85,000 |   | $ | 22.46 |   |

 

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. The table belowshows the aggregate intrinsic values at September 30, 2010 and 2009:

 
| ** **                                                              | ** ** | **2010**  | ** ** | **2009**  | ** ** |
|-------------------------------------------------------------------------|------------|-----------|------------|-----------|------------|
| **Aggregate intrinsic value (in  millions)**                            |       | $         | 0.1        |      | $          | 0.0 |   |
| **Weighted-average remaining  contractual life of outstanding options** |       | 6.8 years |       | 6.8 years |       |
|                                                                         |            |           |            |           |            |  |  |

 

Therange of exercise prices for the options outstanding at September 30,2010, was $18.12 to $23.81. As of September 30, 2010, there was $0.2million of total unrecognized compensation expense related to the non-vestedoptions and related dividend equivalents granted under the plan. That cost willbe recognized 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, 2010, there were 331,021 shares available forissuance in this plan.

 
| ** **                                          | ** ** | **2010** | ** ** | **2009** | ** ** |
|-----------------------------------------------------|------------|----------|------------|----------|------------|
| **Subscriptions outstanding at  September 30** |       | 72,516   |       | 69,725   |       |
| **Maximum subscription price**                      |       | $        | 16.06      |     | $          | 14.62 |   |
| **Shares of stock issued**(1)                       |       | 66,723   |       | 44,265   |       |
| **Stock issuance price**                            |       | $        | 14.62      |     | $          | 14.10 |   |

 

----

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

 

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

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

 

**Note 10- Regulated Operating Expenses**

 

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

 
| ** **                                        | ** ** | **Three  Months  Ended** | ** ** | **Three  Months  Ended** | ** ** | **Nine  Months  Ended** | ** ** | **Nine  Months  Ended** | ** ** | **Twelve  Months  Ended** | ** ** | **Twelve  Months  Ended** | ** ** |
|---------------------------------------------------|------------|--------------------------|------------|--------------------------|------------|-------------------------|------------|-------------------------|------------|---------------------------|------------|---------------------------|------------|
| ** **                                        | ** ** | **2010**                 | ** ** | **2009**                 | ** ** | **2010**                | ** ** | **2009**                | ** ** | **2010**                  | ** ** | **2009**                  | ** ** |
| Electric transmission and distribution expense    |       | $                        | 3,448      |                     | $          | 2,829                   |       | $                       | 9,419      |                      | $          | 8,165                     |       | $ | 12,317 |   | $ | 10,884 |   |
| Natural gas transmission and distribution expense |       | 541                      |       | 540                      |       | 1,588                   |       | 1,614                   |       | 2,135                     |       | 2,169                     |       |
| Power operation expense (other than fuel)         |       | 3,140                    |       | 3,442                    |       | 8,835                   |       | 9,568                   |       | 11,913                    |       | 12,823                    |       |
| Customer accounts and assistance expense          |       | 2,893                    |       | 2,687                    |       | 8,810                   |       | 7,874                   |       | 11,532                    |       | 10,522                    |       |
| Employee pension expense (1)                      |       | 1,355                    |       | 1,456                    |       | 4,106                   |       | 4,143                   |       | 5,520                     |       | 5,464                     |       |
| Employee healthcare plan (1)                      |       | 1,939                    |       | 1,843                    |       | 5,184                   |       | 4,535                   |       | 6,558                     |       | 6,055                     |       |
| General office supplies and expense               |       | 2,778                    |       | 2,675                    |       | 8,159                   |       | 7,500                   |       | 10,729                    |       | 9,484                     |       |
| Administrative and general expense                |       | 2,999                    |       | 2,592                    |       | 9,633                   |       | 8,442                   |       | 13,071                    |       | 12,017                    |       |
| Allowance for uncollectible accounts              |       | 1,179                    |       | 741                      |       | 2,634                   |       | 2,541                   |       | 3,218                     |       | 2,862                     |       |
| Miscellaneous expense                             |       | 37                       |       | 49                       |       | 129                     |       | 49                      |       | 159                       |       | 104                       |       |
| Total                                             |       | $                        | 20,309     |                     | $          | 18,854                  |       | $                       | 58,497     |                      | $          | 54,431                    |       | $ | 77,152 |   | $ | 72,384 |   |

 

----

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

 

30

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**Note 11—Segment Information**

 

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

 

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

 
| ** **                               | ** ** | **For the quarter ended September 30, 2010** | ** ** |
|------------------------------------------|------------|----------------------------------------------------------------------------|------------|
| **($-000’s)**                       | ** ** | **Electric**                                                               | ** ** | **Gas** | ** ** | **Other** | ** ** | **Eliminations** | ** ** | **Total** | ** ** |
|                                     |       |                                                                       |       |   |   |   |   |   |   |   |   |
| **Statement of Operations  Information** |       |                                                                       |       |   |   |   |   |   |   |   |   |
| Revenues                                 |       | $                                                                          | 147,128    |   | $ | 5,403 |   | $ | 1,703 |   | $ | (148 | ) | $ | 154,086 |   |
| Depreciation and amortization            |       | 13,354                                                                     |       | 844 |   | 424 |   | — |   | 14,622 |   |
| Federal and state income taxes           |       | 11,864                                                                     |       | (241 | ) | 297 |   | — |   | 11,920 |   |
| Operating income                         |       | 30,827                                                                     |       | 557 |   | 489 |   | — |   | 31,873 |   |
| Interest income                          |       | 36                                                                         |       | 80 |   | — |   | (86 | ) | 30 |   |
| Interest expense                         |       | 9,392                                                                      |       | 989 |   | 7 |   | (86 | ) | 10,302 |   |
| Income from AFUDC (debt and equity)      |       | 1,605                                                                      |       | 6 |   | — |   | — |   | 1,611 |   |
| Net income                               |       | 22,887                                                                     |       | (388 | ) | 482 |   | — |   | 22,981 |   |
|                                     |       |                                                                       |       |   |   |   |   |   |   |   |   |
| **Capital Expenditures**                 |       | $                                                                          | 21,081     |   | $ | 750 |   | $ | 369 |   |   |   | $ | 22,200 |   |
|                                          |            |                                                                            |            |  |  |  |  |  |  |  |  |  |  |  |  |  |

 
| ** **                              | ** ** | **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 nine months ended September 30, 2010** | ** ** |
|------------------------------------------|------------|-------------------------------------------------------------------------------------|------------|
| **($-000’s)**                       | ** ** | **Electric**                                                                        | ** ** | **Gas** | ** ** | **Other** | ** ** | **Eliminations** | ** ** | **Total** | ** ** |
|                                     |       |                                                                                |       |   |   |   |   |   |   |   |   |
| **Statement of Operations  Information** |       |                                                                                |       |   |   |   |   |   |   |   |   |
| Revenues                                 |       | $                                                                                   | 367,846    |   | $ | 36,480 |   | $ | 4,580 |   | $ | (444 | ) | $ | 408,462 |   |
| Depreciation and amortization            |       | 38,028                                                                              |       | 2,184 |   | 1,182 |   | — |   | 41,394 |   |
| Federal and state income taxes           |       | 24,642                                                                              |       | 981 |   | 718 |   | — |   | 26,341 |   |
| Operating income                         |       | 56,700                                                                              |       | 4,334 |   | 1,196 |   | — |   | 62,230 |   |
| Interest income                          |       | 169                                                                                 |       | 339 |   | — |   | (356 | ) | 152 |   |
| Interest expense                         |       | 30,099                                                                              |       | 2,959 |   | 28 |   | (356 | ) | 32,730 |   |
| Income from AFUDC (debt and equity)      |       | 10,097                                                                              |       | 12 |   | — |   | — |   | 10,109 |   |
| Net income                               |       | 36,216                                                                              |       | 1,553 |   | 1,167 |   | — |   | 38,936 |   |
|                                     |       |                                                                                |       |   |   |   |   |   |   |   |   |
| **Capital Expenditures**                 |       | $                                                                                   | 74,862     |   | $ | 1,636 |   | $ | 2,328 |   |   |   | $ | 78,826 |   |
|                                          |            |                                                                                     |            |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

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

 
| ** **                               | ** ** | **For the twelve months ended September 30, 2010** | ** ** |
|------------------------------------------|------------|---------------------------------------------------------------------------------------|------------|
| **($-000’s)**                       | ** ** | **Electric**                                                                          | ** ** | **Gas** | ** ** | **Other** | ** ** | **Eliminations** | ** ** | **Total** | ** ** |
|                                     |       |                                                                                  |       |   |   |   |   |   |   |   |   |
| **Statement of Operations  Information** |       |                                                                                  |       |   |   |   |   |   |   |   |   |
| Revenues                                 |       | $                                                                                     | 470,911    |   | $ | 52,993 |   | $ | 6,019 |   | $ | (592 | ) | $ | 529,331 |   |
| Depreciation and amortization            |       | 50,196                                                                                |       | 2,691 |   | 1,554 |   | — |   | 54,441 |   |
| Federal and state income taxes           |       | 27,148                                                                                |       | 1,619 |   | 922 |   | — |   | 29,689 |   |
| Operating income                         |       | 70,541                                                                                |       | 6,290 |   | 1,535 |   | — |   | 78,366 |   |
| Interest income                          |       | 210                                                                                   |       | 400 |   | — |   | (421 | ) | 189 |   |
| Interest expense                         |       | 40,753                                                                                |       | 3,946 |   | 36 |   | (421 | ) | 44,314 |   |
| Income from AFUDC (debt and equity)      |       | 13,949                                                                                |       | 13 |   | — |   | — |   | 13,962 |   |
| Net income                               |       | 42,902                                                                                |       | 2,462 |   | 1,499 |   | — |   | 46,863 |   |
|                                     |       |                                                                                  |       |   |   |   |   |   |   |   |   |
| **Capital Expenditures**                 |       | $                                                                                     | 109,992    |   | $ | 2,337 |   | $ | 2,677 |   |   |   | $ | 115,006 |   |
|                                          |            |                                                                                       |            |  |  |  |  |  |  |  |  |  |  |  |  |  |

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

 

**As of September 30, 2010**

 
| **($-000’s)**            | ** ** | **Electric** | ** ** | **Gas(1)** | ** ** | **Other** | ** ** | **Eliminations** | ** ** | **Total** | ** ** |
|-------------------------------|------------|--------------|------------|------------|------------|-----------|------------|------------------|------------|-----------|------------|
| **Balance Sheet Information** |       |         |       |       |       |      |       |             |       |      |       |
| Total assets                  |       | $            | 1,809,845  |       | $          | 135,290   |       | $                | 23,039     |      | $          | (83,567 | ) | $ | 1,884,607 |   |
|                               |            |              |            |            |            |           |            |                  |            |           |            |  |  |  |  |  |

 

----

(1) Includes goodwill of $39,492.

 

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**As of December 31, 2009**

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

 

----

(1) Includes goodwill of $39,492.

 

**Note 12—Income Taxes**

 

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

 
| ** **                                                 | ** ** | **Three Months Ended** | ** ** | **Nine Months Ended** | ** ** | **Twelve Months Ended** | ** ** |
|------------------------------------------------------------|------------|----------------------------------|------------|---------------------------------|------------|-----------------------------------|------------|
| ** **                                                 | ** ** | **2010**                         | ** ** | **2009**                        | ** ** | **2010**                          | ** ** | **2009** | ** ** | **2010** | ** ** | **2009** | ** ** |
| Consolidated effective federal and state income  tax rates |       | 34.2                             | %          | 31.7                            | %          | 40.4                              | %          | 33.1 | % | 38.8 | % | 33.1 | % |

 

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

 

ADecember 2009 award from an arbitration panel ordered KCP&L torenegotiate with the IRS a previous $125 million advanced coal investment taxcredit granted for the Iatan 2 plant. The IRS executed a revised memorandum ofunderstanding (MOU) on September 7, 2010, which granted us our share,$17.7 million, of advanced coal investment tax credits in accordance with thearbitration panel’s order. We will utilize these credits to reduce our 2010 taxpayments and 2010 tax liability and, therefore, these amounts are now reflectedas a reduction to accrued taxes. The tax credit will have no significant incomestatement impact as the credits will flow to our customers as we amortize thetax credits over the life of the plant.

 

OnSeptember 16, 2010, we received approximately $26.6 million from theSouthwest Power Administration (SWPA) as payment regarding the decrease inavailable head waters at our hydroelectric generating plant, located on theWhite River at Ozark Beach, Missouri. As part of the Energy and WaterDevelopment Appropriations Act of 2006 (the Appropriations Act), the level ofBull Shoals Lake will be increased an average of 5 feet. The increase at BullShoals will decrease the head waters available for generation at Ozark Beach by5 feet and, thus, reduce our electrical output. The loss in this facility willrequire us to replace it with additional generation from other sources. TheAppropriations Act required the SWPA, in coordination with us and our relevant publicservice commissions, to determine our economic detriment. SWPA issued its FinalDetermination and awarded us $26.6 million. We believe the revised FinalDetermination did not fully comply with the Appropriations Act as it failed tocompensate us for the impact of income taxes associated with the payment. Weare considering several options to resolve this issue so that the income taxesare appropriately considered in the awarded damages. Currently, we haveincreased our current liability for income taxes by $8.3 million inanticipation that we will pay income taxes on the $26.6 million award, but noimpact to our revenues or net income has been recorded to date. However, we may

 

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ultimatelydefer payment of the taxes if we determine that certain sections of theInternal Revenue Code allow such treatment.

 

As part of an agreementreached in our recently completed Missouri electric rate case, effective September 10,2010, we have also agreed to commence an eighteen year amortization of adeferred asset related to the tax benefits of cost of removal. These taxbenefits were flowed through to customers from 1981-2008 and totaledapproximately $11.1 million. We recorded a regulatory asset expecting torecover these benefits from customers in future periods. We estimated theportion of the amortization period where rate recovery would no longer beprobable for this item and wrote off approximately $1.2 million in the firstquarter of 2010. Amortization of the remaining regulatory tax asset will beginin 2011 or 2012, which is also when we expect to be able to request raterecovery of the asset.

 

We do not expect any significantchanges to our unrecognized tax benefits over the next twelve months. Thereserve balance related to unrecognized tax benefits as of December 31,2009 was $906,000 and has not materially changed at September 30, 2010.

 

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

 

**EXECUTIVE SUMMARY**

 

We operate our businesses as three segments: electric, gas and other.The****Empire District Electric Company (EDE)is an operating public utility engaged in the generation, purchase,transmission, distribution and sale of electricity in parts of Missouri,Kansas, Oklahoma and Arkansas. As part of our electric segment, we also providewater service to three towns in Missouri. The Empire District Gas Company (EDG)is our wholly owned subsidiary. It provides natural gas distribution tocustomers in 44 communities in northwest, north central and west centralMissouri. Our other segment consists of our fiber optics business. During thetwelve months ended September 30, 2010, 89.0% of our gross operatingrevenues were provided from sales from our electric segment (including 0.3%from the sale of water), 10.0% from our gas segment and 1.0% from our othersegment.

 

***Earnings***

 

Duringthe third quarter of 2010, basic earnings per weighted average share of commonstock were $0.56 as compared to $0.43 in the third quarter of 2009 and dilutedearnings per weighted average share of common stock were $0.55 as compared to$0.43 in the third quarter of 2009. For the nine months ended September 30,2010, basic and diluted earnings per weighted average share of common stockwere $0.97 as compared to $0.97 for the nine months ended September 30,2009. For the twelve months ended September 30, 2010, basic and dilutedearnings per weighted average share of common stock were $1.19 as compared to$1.20 for the twelve months ended September 30, 2009. The primary positivedrivers for all three periods presented were increased electric revenuesresulting from increased demand due to favorable weather and decreased interestcharges. The primary negative drivers for all three periods presented wereincreased electric operations and maintenance expenses, the dilutive effect ofadditional shares of common stock issued, increased other deductions andchanges in effective tax rates. Also negatively impacting both the nine monthsand twelve months ended September 30, 2010, were the two non-cash chargesin the first quarter of 2010 discussed below.

 

Thetable below sets forth a reconciliation of basic and diluted earnings per sharebetween the three months, nine months and twelve months ended September 30,2009 and September 30, 2010, which is a non-GAAP presentation. Theeconomic substance behind our non-GAAP earning per share (EPS) measure is topresent the after tax impact of significant items and components of thestatement of income on a per share basis before the impact of additional stockissuances.

 

Webelieve this presentation is useful to investors because the statement ofincome does not readily show the EPS impact of the various components,including the effect of new stock

 

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issuances.This could limit the readers’ understanding of the reasons for the EPS changefrom the previous year’s EPS. This information is useful to management, and webelieve this information is useful to investors, to better understand thereasons for the fluctuation in earnings between the prior and current years ona per share basis.

 

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

 
| ** **                                             | ** ** | **Three Months  Ended** | ** ** | **Nine Months  Ended** | ** ** | **Twelve Months  Ended** | ** ** |
|--------------------------------------------------------|------------|------------------------------|------------|-----------------------------|------------|-------------------------------|------------|
| **Earnings Per Share —  September 30, 2009** | ** ** | **$**                        | **0.43**   | ** **                  | **$**      | **0.97**                      | ** ** | **$** | **1.20** | ** ** |
|                                                   |       |                         |       |                        |       |                          |       |
| **Revenues**                                           |       |                         |       |                        |       |                          |       |
| Electric on-system                                     |       | $                            | 0.41       |                        | $          | 0.52                          |       | $ | 0.48 |   |
| Electric off-system and other                          |       | 0.06                         |       | 0.14                        |       | 0.11                          |       |
| Gas                                                    |       | 0.01                         |       | (0.08                       | )          | (0.20                         | )          |
| Other                                                  |       | 0.01                         |       | 0.01                        |       | 0.01                          |       |
| **Expenses**                                           | ** ** | ** **                   | ** ** | ** **                  | ** ** | ** **                    | ** ** |
| Electric fuel and purchased power                      |       | (0.17                        | )          | (0.29                       | )          | (0.23                         | )          |
| Cost of natural gas sold and transported               |       | 0.01                         |       | 0.12                        |       | 0.24                          |       |
| Regulated — electric segment                      |       | (0.03                        | )          | (0.08                       | )          | (0.10                         | )          |
| Regulated —gas segment                            |       | 0.01                         |       | 0.01                        |       | 0.01                          |       |
| Maintenance and repairs                                |       | (0.01                        | )          | (0.02                       | )          | (0.01                         | )          |
| Depreciation and amortization                          |       | (0.03                        | )          | (0.05                       | )          | (0.06                         | )          |
| Other taxes                                            |       | (0.01                        | )          | (0.02                       | )          | (0.01                         | )          |
| Interest charges                                       |       | 0.03                         |       | 0.05                        |       | 0.05                          |       |
| AFUDC                                                  |       | (0.03                        | )          | 0.00                        |       | 0.00                          |       |
| Change in effective income tax rates                   |       | (0.02                        | )          | (0.04                       | )          | (0.03                         | )          |
| Med-D and cost of removal non-cash charges             |       | 0.00                         |       | (0.09                       | )          | (0.09                         | )          |
| Other income and deductions                            |       | (0.03                        | )          | (0.07                       | )          | (0.08                         | )          |
| Dilutive effect of additional shares issued            |       | (0.08                        | )          | (0.11                       | )          | (0.10                         | )          |
| **Earnings Per Share —  September 30, 2010** | ** ** | **$**                        | **0.56**   | ** **                  | **$**      | **0.97**                      | ** ** | **$** | **1.19** | ** ** |

 

**RecentActivities**

 

***New Construction***

 

OnMarch 14, 2006, we entered into contracts to purchase a 50 megawatt, 7.52%undivided interest in the Plum Point Energy Station. The Plum Point EnergyStation met its in-service criteria on August 13, 2010. Plum Point enteredcommercial operation on September 1, 2010.

 

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 own 12%,or approximately 100 megawatts, of the 850-megawatt unit. KCP&L announcedon August 26, 2010, that Iatan 2 had met its in-service criteria on August 26,2010. See Note 7 of “Notes to Consolidated Financial Statements.”

 

***Regulatory Matters***

 

Wehave filed several rate cases which are described below.

 

Astipulated agreement in our 2009 Missouri electric rate case was filed on May 12,2010, calling for an annual increase of $46.8 million, provided the Plum PointGenerating Station met its in-service criteria by August 15, 2010. ThePlum Point Generating Station completed its in-service criteria testing on August 12,2010, with an in-service date of August 13, 2010, and the new rates wereeffective September 10, 2010.

 

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OnSeptember 28, 2010, we filed a rate increase request with the MPSC for anannual increase in base rates for our Missouri electric customers in the amountof $36.5 million, or 9.2% to recover the Iatan 2 costs and other cost ofservice items not included in the recently completed Missouri rate case.KCP&L announced on August 26, 2010, that Iatan 2 had met its in-servicecriteria on August 26, 2010

 

Astipulated agreement in our current Kansas rate case was filed on May 4, 2010,and approved by the KCC on June 25, 2010, calling for a $2.8 million, or 12.4%,increase in base rates effective July 1, 2010.

 

OnAugust 30, 2010, we were granted a two-phase Capital Reliability Rider (CRR) bythe Oklahoma Corporation Commission (OCC) with the first phase effective September1, 2010. In total, the CRR revenue has been specifically limited by the OCC toan overall annual revenue increase of $2.6 million, or 27.67% increase. We willfile a general rate case within six months of the commercial operation date ofIatan 2 to replace the CRR with permanent rates.

 

OnAugust 19, 2010, we filed a rate increase request with the Arkansas PublicService Commission (APSC) for an annual increase in base rates for our Arkansaselectric customers in the amount of $3.2 million, or 27.3%.

 

OnMarch 12, 2010, we filed Generation Formula Rate (GFR) tariffs with the FERCwhich we propose to be utilized for our wholesale customers. On June 30, 2010,three of our on-system wholesale customers were granted intervention in the GFRrate case. On September 15, 2010, the parties agreed to a settlement inprinciple and are now working to finalize the terms of the settlement.

 

In December 2008, the OPC and intervenorsPraxair, Inc. and Explorer Pipeline Company filed Petitions for Writ of Reviewwith the Cole County Circuit Court challenging the tariffs resulting from our2006 Missouri rate case that went into effect January 1, 2007. The Cole CountyCircuit Court issued a ruling on December 8, 2009, affirming the Commission’sReport and Order. OPC, Praxair and Explorer Pipeline filed appeals with theWestern District Court of Appeals. On October 26, 2010, the Western DistrictCourt of Appeals affirmed the Commission’s Report and Order.

 

For additional information, see “Rate Matters”below.

 

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

 

ADecember 2009 award from an arbitration panel ordered KCP&L to renegotiatewith the IRS a previous $125 million advanced coal investment tax creditgranted to our Iatan 2 plant. The IRS executed a revised memorandum ofunderstanding (MOU) on September 7, 2010, which granted us our share, $17.7million, of advanced coal investment tax credits in accordance with thearbitration panel’s order. We will utilize these credits to reduce our 2010 taxpayments and 2010 tax liability. The tax credit will have no significant incomestatement impact as the credits will flow to our customers as we amortize thetax credits over the life of the plant.

 

***Financings***

 

OnAugust 25, 2010, we issued $50 million principal amount of 5.20% first mortgagebonds due September 1, 2040. The net proceeds (after payment of expenses) ofapproximately $49.1 million wereused to redeem $48.3 million aggregate principal amount of our Senior Notes,7.05% Series due 2022 on August 27, 2010.

 

OnMay 28, 2010, we issued $100 million principal amount of 4.65% first mortgagebonds due June 1, 2020. The net proceeds (after payment of expenses) ofapproximately $98.8 million, wereused to redeem all 2 million outstanding shares of our 8.5% trust preferredsecurities totaling $50 million, on June 28, 2010, and to repay short-term debtwhich was incurred, in part, to fund the repayment, at maturity, of our 6.5%first mortgage bonds due 2010.

 

Wesuccessfully completed our equity distribution program during the secondquarter of 2010 and used the net proceeds to repay short-term debt and forgeneral corporate purposes, including the funding of our current constructionprogram. During the second quarter of 2010, we issued and sold 1,192,644 sharesof our common stock pursuant to this equity distribution program, at an averageprice per share of $18.60, resulting in net proceeds to us of approximately$21.5

 

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million(after payment of approximately $0.7 million in commissions to the salesagent). Since inception of the program, in the aggregate, we issued and sold6,535,216 shares pursuant to the program, at an average price per share of$18.36, resulting in net proceeds to us of approximately $116.0 million.

 

***Ozark Beach Plant***

 

Ourhydroelectric generating plant (FERC Project No. 2221), located on the WhiteRiver at Ozark Beach, Missouri, has a generating capacity of 16 megawatts. Wehave a long-term license from FERC to operate this plant which forms LakeTaneycomo in southwestern Missouri. As part of the Energy and Water DevelopmentAppropriations Act of 2006 (the Appropriations Act), a new minimum flow wasestablished with the intent of increasing minimum flows on recreational streamsin Arkansas. To accomplish this, the level of Bull Shoals Lake will beincreased an average of 5 feet. The increase at Bull Shoals will decrease thehead waters available for generation at Ozark Beach by 5 feet, reducing ourelectrical output. We estimate the lost production to be up to 16% of ouraverage annual energy production for this unit. The loss in output from thisfacility will require us to replace it with additional generation from othersources. The Appropriations Act required the Southwest Power 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, 2009 documentingthe procedure they intended to use to calculate the present value of the futurelifetime replacement cost of the electrical energy and capacity lost due to theWhite River Minimum Flows project at Ozark Beach. The actual hydropowercompensation values were to be calculated using the method presented in theFinal Determination and current values for the specified parameters based onthe official implementation date. Assuming a January 1, 2011 date ofimplementation for the White River Minimum Flows project and November 2008values for the specified parameters, the SWPA’s determination at that timeresulted in a present value for the estimated future lifetime replacement costsof the electrical energy and capacity at Ozark Beach of $41.3 million. On June 8,2009, the SWPA published a draft addendum to its January 2009 FinalDetermination Report documenting proposed changes to the SWPA’s methodology,including the inclusion of an additional discount rate source to be used by theSWPA in determination of the present value of the losses. Assuming a January 1,2011 date of implementation for the White River Minimum Flows project andcurrent values for the specified parameters, the SWPA’s Draft Addendum to itsFinal Determination resulted in a present value of $22.3 million for theestimated future lifetime replacement costs of the electrical energy andcapacity at Ozark Beach. On June 17, 2010, the SWPA posted a revised FinalDetermination that our customers’ damages were $26.6 million. On September 16,2010, we received a $26.6 million payment from the SWPA. We believe the revisedFinal Determination did not fully comply with the Appropriations Act as itfailed to compensate us for the impact of income taxes associated with thepayment. We are considering several options in attempting to resolve this issueso that the income taxes are appropriately considered in the awarded damages.The $26.6 million payment will have no material impact on net income as thebenefits will be flowed through to our customers. In addition, the SWPA hasdelayed the implementation date until 2016.

 

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

 

On March 23, 2010, the Patient Protection and Affordable Care Act wasenacted. This legislation includes a provision that reduces the deductibility,for income tax purposes, of retiree healthcare costs to the extent an employerreceives federal subsidies. Companies receive the subsidy when they provideretiree prescription benefits at least equivalent to Medicare Part D coveragein their postretirement healthcare plan. Although the elimination of this taxbenefit does not take effect until 2013, this change requires us to recognizethe full accounting impact in our financial statements in the period in whichthe legislation is enacted. As a result, in the first quarter of 2010, werecorded a one-time non-cash charge of approximately $2.1 million to reflectthe impact of this change. Our 2010 effective tax rate also increased due tothe additional tax expense

 

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associatedwith the current year retiree health care accruals. See Note 12 of “Notes toConsolidated Financial Statements.”

 

***Renewable Energy***

 

OnNovember 4, 2008, Missouri voters approved the Clean Energy Initiative(Proposition C). This initiative requires us and other investor-owned utilitiesin Missouri to generate or purchase electricity from renewable energy sources,such as solar, wind, biomass and hydro power, at the rate of at least 2% ofretail sales by 2011, increasing to at least 15% by 2021. Two percent of thisamount must be solar. We believe we are exempted from this requirement. In July2010, the MPSC submitted to the Missouri secretary of state’s office its rule forthe renewable energy mandate. We are awaiting action from the Missourisecretary of state but believe we are in compliance with the law. Kansasestablished a renewable portfolio standard (RPS) in May 2009. Its finalrulemaking is expected to be released some time in August 2010. In addition,there are several proposals currently before the U.S. Congress to adopt anationwide RPS.

 

***Shareholder Rights Plan***

 

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

 

**RESULTS OF OPERATIONS**

 

The following discussion analyzes significant changes in the results ofoperations for the three-month, nine-month and twelve-month periods ended September30, 2010, compared to the same periods ended September 30, 2009.

 

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

 
| ** ** | ** ** | **Quarter Ended** | ** ** | **Nine Months Ended** | ** ** | **Twelve Months Ended** | ** ** |
|------------|------------|-------------------|------------|-----------------------|------------|-------------------------|------------|
| ** ** | ** ** | **2010**          | ** ** | **2009**              | ** ** | **2010**                | ** ** | **2009** | ** ** | **2010** | ** ** | **2009** | ** ** |
| Electric   |       | $                 | 22.9       |                  | $          | 15.5                    |       | $ | 36.2 |   | $ | 32.4 |   | $ | 42.9 |   | $ | 39.2 |   |
| Gas        |       | (0.4              | )          | (1.0                  | )          | 1.6                     |       | (0.0 | ) | 2.5 |   | 1.1 |   |
| Other      |       | 0.5               |       | 0.3                   |       | 1.1                     |       | 1.0 |   | 1.5 |   | 0.8 |   |
| Net income |       | $                 | 23.0       |                  | $          | 14.8                    |       | $ | 38.9 |   | $ | 33.4 |   | $ | 46.9 |   | $ | 41.1 |   |

 

----

**Differences could occur due to rounding.*

 

***Electric Segment***

 

**Overview**

 

Our electric segment net income for the third quarter of 2010 was $22.9million as compared to $15.5 million for the third quarter of 2009.

 

Electric operating revenues comprised approximately 95.2% of our totaloperating revenues during the third quarter of 2010. Of our total electricoperating revenues during the third quarter of 2010, approximately 43.3% werefrom residential customers, 30.9% from commercial customers, 14.4% fromindustrial customers, 4.0% from wholesale on-system customers, 3.4% fromwholesale off-system transactions, 2.5% from other electric revenues, primarilypublic authorities, and 1.5% from miscellaneous sources. The percentage ofrevenues provided from our wholesale off-system transactions increased duringthe third quarter of 2010 as compared to the third quarter of 2009, resultingfrom higher demand in the third quarter of 2010 primarily due to warmertemperatures as compared to the third quarter of 2009.

 

The amounts and percentage changes from the prior periods inkilowatt-hour (“kWh”) sales and operating revenues by major customer class foron-system sales and for off-system sales for the applicable periods ended September30, were as follows:

 

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| ** **            | ** ** | **kWh Sales**     | ** ** |
|-----------------------|------------|-------------------|------------|
| ** **            | ** ** | **(in millions)** | ** ** |
| ** **            | ** ** | **3 Months**      | ** ** | **3 Months** | ** ** | ** ** | ** ** | **9 Months** | ** ** | **9 Months** | ** ** | ** ** | ** ** | **12 Months** | ** ** | **12 Months** | ** ** | ** ** | ** ** |
| ** **            | ** ** | **Ended**         | ** ** | **Ended** | ** ** | **%** | ** ** | **Ended** | ** ** | **Ended** | ** ** | **%** | ** ** | **Ended** | ** ** | **Ended** | ** ** | **%** | ** ** |
| **Customer  Class**   | ** ** | **2010**          | ** ** | **2009** | ** ** | **Change*** | ** ** | **2010** | ** ** | **2009** | ** ** | **Change*** | ** ** | **2010** | ** ** | **2009** | ** ** | **Change*** | ** ** |
| Residential           |       | 586.4             |       | 471.0 |   | 24.5 | % | 1,621.9 |   | 1,409.1 |   | 15.1 | % | 2,079.3 |   | 1,883.3 |   | 10.4 | % |
| Commercial            |       | 461.7             |       | 408.3 |   | 13.1 |   | 1,252.9 |   | 1,188.2 |   | 5.4 |   | 1,644.6 |   | 1,592.4 |   | 3.3 |   |
| Industrial            |       | 272.3             |       | 265.6 |   | 2.5 |   | 762.7 |   | 757.9 |   | 0.6 |   | 997.0 |   | 1,010.3 |   | (1.3 | ) |
| Wholesale on-system   |       | 102.8             |       | 89.4 |   | 15.1 |   | 273.2 |   | 252.9 |   | 8.0 |   | 352.3 |   | 334.0 |   | 5.5 |   |
| Other**               |       | 33.8              |       | 30.8 |   | 9.6 |   | 97.2 |   | 92.8 |   | 4.7 |   | 127.7 |   | 122.5 |   | 4.3 |   |
| Total on-system sales |       | 1,457.0           |       | 1,265.1 |   | 15.2 |   | 4,007.9 |   | 3,700.9 |   | 8.3 |   | 5,200.9 |   | 4,942.5 |   | 5.2 |   |
| Off-system            |       | 158.2             |       | 100.6 |   | 57.3 |   | 554.0 |   | 346.3 |   | 60.0 |   | 723.6 |   | 560.6 |   | 29.1 |   |
| Total KWh Sales       |       | 1,615.2           |       | 1,365.7 |   | 18.3 |   | 4,561.9 |   | 4,047.2 |   | 12.7 |   | 5,924.5 |   | 5,503.1 |   | 7.7 |   |

 

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

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

 
| ** **                                | ** ** | **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**                       | ** ** | **2010**                                | ** ** | **2009** | ** ** | **Change*** | ** ** | **2010** | ** ** | **2009** | ** ** | **Change*** | ** ** | **2010** | ** ** | **2009** | ** ** | **Change*** | ** ** |
| Residential                               |       | $                                       | 63.5       |   | $ | 49.9 |   | 27.0 | % | $ | 157.8 |   | $ | 138.0 |   | 14.4 | % | $ | 200.2 |   | $ | 181.2 |   | 10.5 | % |
| Commercial                                |       | 45.2                                    |       | 39.3 |   | 15.2 |   | 109.8 |   | 104.2 |   | 5.3 |   | 141.4 |   | 136.5 |   | 3.5 |   |
| Industrial                                |       | 21.2                                    |       | 19.7 |   | 7.6 |   | 52.3 |   | 51.3 |   | 2.0 |   | 67.0 |   | 66.8 |   | 0.3 |   |
| Wholesale on-system                       |       | 5.9                                     |       | 5.1 |   | 16.5 |   | 15.4 |   | 14.1 |   | 9.2 |   | 19.5 |   | 18.4 |   | 6.3 |   |
| Other**                                   |       | 3.6                                     |       | 3.3 |   | 8.8 |   | 9.3 |   | 8.9 |   | 4.8 |   | 12.0 |   | 11.5 |   | 4.5 |   |
| Total on-system revenues                  |       | $                                       | 139.4      |   | $ | 117.3 |   | 18.8 |   | $ | 344.6 |   | $ | 316.5 |   | 8.9 |   | $ | 440.1 |   | $ | 414.4 |   | 6.2 |   |
| Off-system                                |       | 5.0                                     |       | 2.7 |   | 87.4 |   | 16.3 |   | 9.3 |   | 76.3 |   | 21.4 |   | 16.3 |   | 31.3 |   |
| Total revenues from kWh sales             |       | 144.4                                   |       | 120.0 |   | 20.4 |   | 360.9 |   | 325.8 |   | 10.8 |   | 461.5 |   | 430.7 |   | 7.2 |   |
| Miscellaneous revenues***                 |       | 2.2                                     |       | 1.5 |   | 45.3 |   | 5.5 |   | 4.7 |   | 16.7 |   | 7.6 |   | 6.5 |   | 15.8 |   |
| Total electric operating revenues         |       | $                                       | 146.6      |   | $ | 121.5 |   | 20.7 |   | $ | 366.4 |   | $ | 330.5 |   | 10.9 |   | $ | 469.1 |   | $ | 437.2 |   | 7.3 |   |
| Water revenues                            |       | 0.5                                     |       | 0.5 |   | 7.1 |   | 1.4 |   | 1.3 |   | 3.3 |   | 1.8 |   | 1.8 |   | 3.0 |   |
| Total electric segment operating Revenues |       | $                                       | 147.1      |   | $ | 122.0 |   | 20.6 |   | $ | 367.8 |   | $ | 331.8 |   | 10.9 |   | $ | 470.9 |   | $ | 439.0 |   | 7.3 |   |

 

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

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

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

 

Withthe addition of the Missouri fuel adjustment mechanism effective September 1,2008, we now have a fuel cost recovery mechanism in all of our jurisdictions,which significantly reduces the impact of fluctuating fuel costs on our netincome. For this reason, we believe electric gross margin, although a non-GAAPmeasurement, is useful for understanding and analyzing changes in our electricoperating performance from one period to the next. We define electric grossmargins as electric revenues less fuel and purchased power costs.

 

Thetable below represents our electric gross margins for the applicable periodsended September 30 (in millions), which is a non-GAAP presentation. We believethis presentation is useful to investors and have included the analysis belowas a complement to the financial information we provide in accordance withGAAP. However, these margins may not be comparable to other companies’presentations or more useful than the GAAP information we provide elsewhere inthis report.

 
| ** **               | ** ** | **Quarter Ended** | ** ** | **Nine Months Ended** | ** ** | **Twelve Months Ended** | ** ** |
|--------------------------|------------|-------------------|------------|-----------------------|------------|-------------------------|------------|
| ** **               | ** ** | **2010**          | ** ** | **2009**              | ** ** | **2010**                | ** ** | **2009** | ** ** | **2010** | ** ** | **2009** | ** ** |
| Electric revenues        |       | $                 | 146.6      |                  | $          | 121.5                   |       | $ | 366.4 |   | $ | 330.5 |   | $ | 469.1 |   | $ | 437.2 |   |
| Fuel and purchased power |       | 57.3              |       | 48.1                  |       | 152.2                   |       | 136.5 |   | 197.8 |   | 185.1 |   |
| Electric gross margins   |       | $                 | 89.3       |                  | $          | 73.4                    |       | $ | 214.2 |   | $ | 194.0 |   | $ | 271.3 |   | $ | 252.1 |   |

 

Electricgross margins increased****during 2010 inall periods presented mainly due to increased electric sales resulting fromfavorable weather as compared to the comparable periods in 2009.

 

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***Quarter Ended September 30, 2010 Compared to Quarter Ended September 30,2009***

 

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

 

KWh sales and revenues for our on-system customers increased during thethird quarter of 2010 as compared to the third quarter of 2009 primarily due towarmer weather in the third quarter of 2010 as compared to the same period in2009. Revenues for our on-system customers increased approximately $22.1million, or 18.8%. Weather and other related factors increased revenues by anestimated $18.3 million compared to last year’s third quarter. Total coolingdegree days (the cumulative number of degrees that the average temperature foreach day during that period was above 65*°* F) for the third quarter of2010 were 72.9% more than the same period last year and 20.9% more than the30-year average. Rate changes, including the July 2010 Kansas rate increase andSeptember 2010 Missouri rate increase (discussed below), contributed anestimated $3.0 million to revenues during the third quarter of 2010.Residential and commercial sales growth increased revenues an estimated $0.8million. Our electric customer growth for the twelve months ended September 30,2010, was 0.4%.

 

Residential and commercial kWh sales and revenues increased during thethird quarter of 2010 mainly due to the warmer temperatures in the thirdquarter of 2010.

 

Industrial kWh sales and revenues increased during the third quarter of2010 as compared to the third quarter of 2009 when there was a slowdown createdby economic uncertainty.

 

On-system wholesale kWh sales and revenues increased during the thirdquarter of 2010 reflecting increased demand resulting from the warmer weatherdiscussed above. These revenues are currently being collected under a tariffsubject to refund (see “Rate Matters”below for additional information) under our pending FERC rate case and are netof an estimated $0.3 million of revenues subject to refund.

 

**Off-System Electric Transactions**

 

Inaddition to sales to our own customers, we also sell power to other utilitiesas available, including through the Southwest Power Pool (SPP) energy imbalanceservices (EIS) market. See “— Competition” below. The majority of ouroff-system sales margins are now included as a component of the fuel adjustmentclause in our Missouri, Kansas and Oklahoma jurisdictions and generally adjustthe fuel and purchased power expense. As a result, nearly all of the off-systemsales margin flows back to the customer and has little effect on income.

 

Off-system revenues and related expenses were more during the thirdquarter of 2010 as compared to the third quarter of 2009 primarily due toincreased market demand resulting from the warmer weather in the third quarterof 2010. Total purchased power related expenses are included in our discussionof purchased power costs below.

 

**Miscellaneous Revenues**

 

Our miscellaneous revenues were $2.2 million for the third quarter of2010 as compared to $1.5 million in the third quarter of 2009. These revenuesare comprised mainly of transmission revenues, late payment fees and renewableenergy credit (REC) sales. REC sales were responsible for approximately $0.3million of the increase.

 

**Operating Revenue Deductions — Fuel and Purchased Power**

 

Duringthe third quarter of 2010, total fuel and purchased power expenses increasedapproximately $9.2 million (19.0%). The table below is a reconciliation of ouractual fuel and purchased power expenditures (netted with the regulatoryadjustments) to the fuel and purchased power expense shown on our statement ofincome for the third quarter of 2010 and 2009.

 

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| **(in millions)**                                            | ** ** | **2010** | ** ** | **2009** | ** ** |
|--------------------------------------------------------------|------------|----------|------------|----------|------------|
| Actual fuel and purchased power expenditures                 |       | $        | 59.6       |     | $          | 47.1 |   |
| Iatan 2 construction accounting***                           |       | 0.3      |       | —   |       |
| Kansas regulatory adjustments*                               |       | 0.1      |       | 0.1      |       |
| Missouri fuel adjustment deferral*                           |       | (5.1     | )          | 0.4      |       |
| Missouri fuel adjustment recovery**                          |       | 2.0      |       | 0.9      |       |
| Unrealized loss/(gain) on derivatives                        |       | 0.4      |       | (0.4     | )          |
| Total fuel and purchased power expense per income  statement |       | $        | 57.3       |     | $          | 48.1 |   |

 

----

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

**Currently being recovered from customers from prior accumulationperiods.

***See “Rate Matters” below.

 

Theoverall fuel and purchased power increase reflects increased generation by bothour coal-fired and gas-fired units during the third quarter of 2010 reflectingincreased market demand resulting from the warmer weather in the third quarterof 2010.

 

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

 
| ** **                           | ** ** | **Three Months Ended**          | ** ** |
|--------------------------------------|------------|---------------------------------|------------|
| **(in millions)**                    | ** ** | **September 30, 2010 vs. 2009** | ** ** |
| Natural gas generation volume        |       | $                               | 18.5       |   |
| Coal generation volume               |       | 0.8                             |       |
| Purchased power spot purchase volume |       | (1.9                            | )          |
| Purchased power (cost per mWh)       |       | 1.5                             |       |
| Natural gas (cost per mWh)           |       | (6.5                            | )          |
| Coal (cost per mWh)                  |       | (0.2                            | )          |
| Other (primarily fuel adjustments)   |       | (3.0                            | )          |
| TOTAL                                |       | $                               | 9.2        |   |

 

**Operating Revenue Deductions — Other Than Fuel and Purchased Power**

 

Regulatedoperating expenses increased approximately $1.7 million (10.2%) during thethird quarter of 2010 as compared to the same period in 2009 primarily due toincreases of $0.6 million in transmission expense, $0.6 million in customeraccounts expense (mainly increased uncollectible accounts and banking fees),$0.2 million in employee pension expense, $0.2 million in steam power expense,$0.1 million in other power operation expense, $0.1 million in customerassistance expense, $0.1 million in property insurance, $0.1 million inemployee health care expense, $0.1 million in general office expense and $0.1million in general labor costs.****Theseincreases were partially offset by decreases of $0.2 million in professionalservices and $0.3 million in other steam power expense related to Iatan 1 andIatan 2 operating costs that we were able to defer in accordance with ouragreement with the MPSC that allows deferral of certain costs until the plantadditions are included in our rate base.

 

Maintenance and repairs expense increased approximately $0.6 million(7.4%) in the third quarter of 2010 as compared to 2009 primarily due toincreases of $0.5 million in maintenance and repairs expense at the Asburyplant, which was mainly due to a maintenance outage in September 2010, $0.2million in maintenance and repairs expense at the Plum Point plant and $0.2million in transmission maintenance expense. These increases were partiallyoffset by a decrease of $0.3 million in distribution maintenance expense.

 

Depreciation and amortization expense increased approximately $1.2million (9.9%) during the quarter primarily reflecting our additions to plantin service and to additional regulatory

 

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amortization of $0.6 million effective September 10, 2010. Thisincludes the construction accounting effect of deferring $0.5 million of Iatan1 and Iatan 2 depreciation expense. Other taxes increased approximately $0.5million during the third quarter of 2010 due to increased municipal franchisetaxes.

 

***Nine Months Ended September 30, 2010 Compared toNine Months Ended September 30, 2009***

 

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

 

KWh sales for our on-system customers increased during the nine monthsended September 30, 2010, as compared to the nine months ended September 30,2009, primarily due to colder weather in the first quarter of 2010 and warmerweather in the second and third quarters of 2010 as compared to the sameperiods in 2009. Revenues for our on-system customers increased approximately$28.1 million, or 8.9%. Weather and other related factors increased revenues byan estimated $25.0 million compared to the nine months ended September 30,2009. Rate changes, including the July 2010 Kansas rate increase and September 2010Missouri rate increase, contributed an estimated $1.4 million during the ninemonths ended September 30, 2010, while sales growth contributed an estimated$1.6 million.

 

The increase in residential and commercial kWh sales and revenuesduring the nine months ended September 30, 2010, was primarily due to thefavorable weather in 2010.

 

Industrial kWh sales and revenues increased during the nine monthsended September 30, 2010, as compared to the comparable period in 2009 whenthere was a slowdown created by economic uncertainty.

 

On-system wholesale kWh sales and revenues increased during the ninemonths ended September 30, 2010, reflecting the favorable weather discussedabove.

 

**Off-System Electric Transactions**

 

Off-system revenues and related expenses were more during the ninemonths ended September 30, 2010, as compared to the same period in 2009primarily due to increased market demand resulting from the warmer weather inthe second and third quarters of 2010 and colder weather in the first quarterof 2010. Total purchased power related expenses are included in our discussionof purchased power costs below.

 

**Miscellaneous Revenues**

 

Our miscellaneous revenues were $5.5 million for the nine months ended September30, 2010, as compared to $4.7 million during the same period in 2009. Theserevenues are comprised mainly of transmission revenues, late payment fees andrenewable energy credit sales, which were responsible for approximately $0.6million of the increase.

 

**Operating Revenue Deductions — Fuel and Purchased Power**

 

During the nine months ended September 30, 2010, total fuel andpurchased power expenses increased approximately $15.7 million (11.5%). The tablebelow is a reconciliation of our actual fuel and purchased power expenditures(netted with the regulatory adjustments) to the fuel and purchased powerexpense shown on our statement of income for the nine months ended September 30,2010 and 2009.

 

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| **(in millions)**                                       | ** ** | **2010** | ** ** | **2009** | ** ** |
|--------------------------------------------------------------|------------|----------|------------|----------|------------|
| Actual fuel and purchased power expenditures                 |       | $        | 157.6      |     | $          | 135.5 |   |
| Iatan 2 construction accounting***                           |       | 0.3      |       | —   |       |
| Kansas regulatory adjustments*                               |       | (0.3     | )          | 0.5      |       |
| Missouri fuel adjustment deferral*                           |       | (7.7     | )          | (0.2     | )          |
| Missouri fuel adjustment recovery**                          |       | 1.5      |       | 1.1      |       |
| Unrealized loss/(gain) on derivatives                        |       | 0.8      |       | (0.4     | )          |
| Total fuel and purchased power expense per income  statement |       | $        | 152.2      |     | $          | 136.5 |   |

 

----

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

**Currently being recovered from customers from prior accumulationperiods.

***See “Rate Matters” below.

 

Theoverall fuel and purchased power increase reflects increased market demandresulting from the warmer weather in the second and third quarters of 2010 andcolder weather in the first quarter of 2010 as compared to the prior yearsperiods.

 

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 30,2010, as compared to the nine months ended September 30, 2009. This tableincorporates all the changes mentioned above. As shown below, the largestimpact on fuel and purchased power costs was increased generation by ourgas-fired units.

 
| **(in millions)**               | ** ** | **Nine Months Ended  September 30, 2010 vs. 2009** | ** ** |
|--------------------------------------|------------|----------------------------------------------------------------------------------|------------|
| Natural gas generation volume        |       | $                                                                                | 33.2       |   |
| Coal generation volume               |       | 3.1                                                                              |       |
| Purchased power spot purchase volume |       | (5.4                                                                             | )          |
| Purchased power (cost per mWh)       |       | 4.3                                                                              |       |
| Natural gas (cost per mWh)           |       | (12.5                                                                            | )          |
| Coal (cost per mWh)                  |       | (0.8                                                                             | )          |
| Other (primarily fuel adjustments)   |       | (6.2                                                                             | )          |
| TOTAL                                |       | $                                                                                | 15.7       |   |

 

**Operating Revenue Deductions — Other Than Fuel and Purchased Power**

 

Regulatedoperating expenses for our electric segment increased approximately $4.8million (10.1%) during the nine months ended September 30, 2010, ascompared to the same period in 2009 primarily due to increases of $1.0 millionin customer accounts expenses (mainly increased banking fees and uncollectibleaccounts), $0.9 million in transmission expense, $0.6 million in employeehealth care expense, $0.5 million in general labor costs, $0.4 million inemployee pension expense, $0.4 million in distribution expense, $0.3 million inproperty insurance, $0.2 million in other power supply expense, $0.2 million inother power operation expense, $0.2 million in customer assistance expense,$0.2 million in director, stockholder and other investor expense, $0.2 millionin general office expense, $0.1 million in steam power other operation expense,$0.1 million in injuries and damages, $0.1 million in regulatory commissionexpense and $0.1 million in research and development expense. These increaseswere partially offset by $0.9 million in other steam power expense related toIatan 1 and Iatan 2 operating costs that we were able to defer in accordancewith our agreement with the MPSC.

 

Maintenance and repairs expense increased approximately $1.3 million(5.6%) during the nine months ended September 30, 2010, as compared to2009 primarily due to increases of $1.0 million in maintenance and repairsexpense at the Asbury plant, which was mainly due to maintenance outages in May andSeptember 2010, $0.9 million in maintenance and repairs expense at theRiverton plant due to the 2010 5-year maintenance outage, $0.4 million intransmission maintenance, $0.3 million in maintenance and repairs expense atthe Iatan plant, $0.2 million in maintenance and repairs expense at the PlumPoint plant and $0.1 million in distribution maintenance. These increases werepartially offset by a $1.6 million decrease in other power

 

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maintenance expense, which was almost entirely due to the result of adecrease in maintenance and repairs expense at the SLCC plant as compared to2009 when there was a maintenance outage at the plant in the first quarter.

 

Depreciation and amortization expense increased approximately $2.2million (6.0%) during the nine months ended September 30, 2010, primarilyreflecting our additions to plant in service and to additional regulatoryamortization of $0.6 million effective September 10, 2010. This includesthe construction accounting effect of deferring $1.2 million of Iatan 1 andIatan 2 depreciation expense. Other taxes increased approximately $1.1 millionduring the nine months ended September 30, 2010, due to increased propertytax reflecting our additions to plant in service and increased municipalfranchise taxes.

 

***Twelve Months Ended September 30, 2010Compared to Twelve Months Ended September 30, 2009***

 

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

 

For the twelve months ended September 30, 2010, kWh sales to ouron-system customers increased 5.2% with the associated revenues increasingapproximately $25.7 million (6.2%). Weather and other related factors increasedrevenues an estimated $20.8 million. Rate changes, including the July 2010Kansas rate increase and September 2010 Missouri rate increase,contributed an estimated $3.4 million to revenues while continued sales growthcontributed an estimated $1.5 million.

 

The increase in residential and commercial kWh sales and revenuesduring the twelve months ended September 30, 2010, was primarily due tothe favorable weather during the period. Industrial kWh sales decreased 1.3%mainly due to general economic conditions while the associated revenuesincreased 0.3% mainly due to the Kansas and Missouri rate increases.****On-system wholesale kWh sales and revenues increasedreflecting increased market demand resulting from the warmer weather in thesecond and third quarters of 2010 and colder weather in the first quarter of2010.

 

**Off-System Electric Transactions**

 

Off-system sales and revenues increased during the twelve months ended September 30,2010, as compared to the same period in 2009 primarily due to the favorableweather discussed above. Total purchased power related expenses are included inour discussion of purchased power costs below.

 

**Miscellaneous Revenues**

 

Our miscellaneous revenues were $7.6 million for the twelve monthsended September 30, 2010, as compared to $6.5 million during the sameperiod in 2009. These revenues are comprised mainly of transmission revenues,late payment fees and renewable energy credit sales, which were responsible forapproximately $1.2 million of the increase.

 

**Operating Revenue Deductions — Fuel and Purchased Power**

 

During the twelve months ended September 30, 2010, total fuel andpurchased power expenses increased approximately $12.6 million (6.8%). Thetable below is a reconciliation of our actual fuel and purchased powerexpenditures (netted with the regulatory adjustments) to the fuel and purchasedpower expense shown on our statement of operations for the twelve months ended September 30,2010 and 2009.

 

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| **(in millions)**                                       | ** ** | **2010** | ** **  | **2009** | ** ** |
|--------------------------------------------------------------|------------|----------|-------------|----------|------------|
| Actual fuel and purchased power expenditures                 |       | $        |  204.2 |     | $          |  185.5 |   |
| Iatan 2 construction accounting***                           |       | 0.3      |        | —   |       |
| Kansas regulatory adjustments*                               |       | (0.3     | )           | 0.6      |       |
| Missouri fuel adjustment deferral*                           |       | (9.4     | )           | (2.0     | )          |
| Missouri fuel adjustment recovery**                          |       | 2.1      |        | 1.1      |       |
| Unrealized loss on derivatives                               |       | 0.9      |        | —   |       |
| Total fuel and purchased power expense per income  statement |       | $        |  197.8 |     | $          |  185.2 |   |

 

----

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

**Currently being recovered from customers from prior accumulationperiods.

***See “Rate Matters” below.

 

Theoverall fuel and purchased power increase includes the effect of decreasedmarket demand resulting from mild weather in the fourth quarter of 2009 offsetby increased demand in 2010 due to favorable weather conditions.

 

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

 
| **(in millions)**               | ** ** | **Twelve Months Ended  September 30, 2010 vs. 2009** | ** **              |
|--------------------------------------|------------|------------------------------------------------------------------------------------|-------------------------|
| Natural gas generation volume        |       | $                                                                                  |     14.5 |   |
| Coal generation volume               |       | 5.1                                                                                |                    |
| Purchased power spot purchase volume |       |    (4.6                                                                  | )                       |
| Purchased power (cost per mWh)       |       | 5.5                                                                                |                    |
| Natural gas (cost per mWh)           |       | (1.1                                                                               | )                       |
| Coal (cost per mWh)                  |       | (1.0                                                                               | )                       |
| Other (primarily fuel adjustments)   |       | (5.8                                                                               | )                       |
| TOTAL                                |       | $                                                                                  |    12.6       |   |

 

**Operating Revenue Deductions — Other Than Fuel and Purchased Power**

 

Regulatedoperating expenses increased approximately $5.3 million (8.5%) during thetwelve months ended September 30, 2010, as compared to 2009 primarily dueto increases of $1.3 million in customer accounts expense (mainly increasedbanking fees and uncollectible accounts), $1.0 million in general labor costs,$1.0 million in transmission expense, $0.6 million in employee pension expense,$0.4 million in employee health care expense, $0.4 million in distributionexpense, $0.4 million in property insurance, $0.3 million in other steam powerexpense, $0.3 million in other power supply expense, $0.3 million in generaloffice expense, $0.3 million in professional services, $0.1 million in researchand development expense, $0.1 million in employee welfare costs and $0.1million in director, stockholder and other investor expense. These increaseswere partially offset by $1.1 million in other steam power expense related toIatan 1 and Iatan 2 operating costs that we were able to defer in accordancewith our agreement with the MPSC that allows deferral of certain costs untilthe plant additions are included in our rates. A decrease of $0.3 million ininjuries and damages also decreased operating expenses.

 

Maintenanceand repairs expense increased approximately $0.5 million (1.5%) during thetwelve months ended September 30, 2010, as compared to 2009 primarily dueto increases of $1.5 million in maintenance and repairs expense at the Asburyplant, which was mainly due to maintenance outages in May and September 2010,$0.7 million in maintenance and repairs expense at the Riverton plant due tothe 2010 5-year maintenance outage, $0.4 million in transmission maintenanceexpense, $0.2 million in maintenance and repairs expense at the Plum Pointplant, $0.1 million in maintenance and repairs expense at the Ozark Beach plantand $0.1 million in repairs expense to the Riverton gas units. These increaseswere partially offset by

 

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decreasesof $2.0 million in maintenance and repairs expense to the SLCC, whichexperienced a maintenance outage in the first quarter of 2009, and $0.4 millionin maintenance and repairs expense at the Iatan 1 plant, which experienced anoutage in the fourth quarter of 2008.

 

Depreciation and amortization expense increased approximately $2.5million (5.2%) during the twelve months ended September 30, 2010,reflecting our additions to plant in service and to additional regulatoryamortization of $0.6 million effective September 10, 2010. This includesthe construction accounting effect of deferring $1.5 million of Iatan 1 andIatan 2 depreciation expense. Other taxes increased approximately $1.1 millionduring the twelve months ended September 30, 2010, due to increasedproperty tax reflecting our additions to plant in service and increasedmunicipal franchise taxes.

 

***Gas Segment***

 

**Gas Operating Revenues and Sales**

 

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

 

**Total Gas Delivered toCustomers**

 
| ** **                 | ** ** | **Three Months Ended** | ** ** | **%**    | ** ** | **Nine Months Ended** | ** ** | **%**    | ** ** | **Twelve Months Ended** | ** ** | **%**      | ** ** |
|----------------------------|------------|----------------------------------|------------|----------|------------|---------------------------------|------------|----------|------------|-----------------------------------|------------|------------|------------|
| **(bcf sales)**       | ** ** | **2010**                         | ** ** | **2009** | ** ** | **change**                      | ** ** | **2010** | ** ** | **2009**                          | ** ** | **change** | ** ** | **2010** | ** ** | **2009** | ** ** | **change** | ** ** |
| Residential                |       | 0.10                             |       | 0.13     |       | (20.4                           | )%         | 1.81     |       | 1.74                              |       | 4.6        | %          | 2.77 |   | 2.72 |   | 1.5 | % |
| Commercial                 |       | 0.11                             |       | 0.12     |       | (6.6                            | )          | 0.88     |       | 0.84                              |       | 5.1        |       | 1.32 |   | 1.30 |   | 1.9 |   |
| Industrial*                |       | 0.02                             |       | 0.02     |       | 4.1                             |       | 0.08     |       | 0.18                              |       | (58.9      | )          | 0.11 |   | 0.40 |   | (72.8 | ) |
| Other**                    |       | 0.00                             |       | 0.00     |       | (16.6                           | )          | 0.03     |       | 0.02                              |       | 23.1       |       | 0.03 |   | 0.03 |   | 14.7 |   |
| Total  retail sales        |       | 0.23                             |       | 0.27     |       | (12.9                           | )          | 2.80     |       | 2.78                              |       | 0.7        |       | 4.23 |   | 4.45 |   | (5.0 | ) |
| Transportation  sales      |       | 0.86                             |       | 0.88     |       | (2.9                            | )          | 3.54     |       | 2.96                              |       | 19.6       |       | 4.91 |   | 4.05 |   | 21.4 |   |
| Total  gas operating sales |       | 1.09                             |       | 1.15     |       | (5.2                            | )          | 6.34     |       | 5.74                              |       | 10.4       |       | 9.14 |   | 8.50 |   | 7.6 |   |

 

**Operating Revenues andCost of Gas Sold**

 
| ** **                                        | ** ** | **Three  Months Ended** | ** ** | ** ** | ** ** | **Nine  Months Ended** | ** ** | ** ** | ** ** | **Twelve  Months Ended** | ** ** | ** **        | ** ** |
|---------------------------------------------------|------------|-------------------------|------------|------------|------------|------------------------|------------|------------|------------|--------------------------|------------|-------------------|------------|
| **($ in millions)**                     | ** ** | **2010**                | ** ** | **2009**   | ** ** | **% change**      | ** ** | **2010**   | ** ** | **2009**                 | ** ** | **% change** | ** ** | **2010** | ** ** | **2009** | ** ** | **% change** | ** ** |
| Residential                                       |       | $                       | 3.0        |       | $          | 2.5                    |       | 16.8       | %          | $                        | 23.1       |              | $          | 25.5 |   | (9.5 | )% | $ | 33.7 |   | $ | 39.4 |   | (14.4 | )% |
| Commercial                                        |       | 1.5                     |       | 1.5        |       | (3.0                   | )          | 9.6        |       | 11.0                     |       | (13.0             | )          | 14.1 |   | 17.1 |   | (17.6 | ) |
| Industrial*                                       |       | 0.1                     |       | 0.2        |       | (24.6                  | )          | 0.6        |       | 1.8                      |       | (67.1             | )          | 0.9 |   | 3.9 |   | (77.4 | ) |
| Other**                                           |       | 0.0                     |       | 0.0        |       | 11.9                   |       | 0.2        |       | 0.3                      |       | (0.4              | )          | 0.4 |   | 0.4 |   | (7.6 | ) |
| Total  retail revenues                            |       | $                       | 4.6        |       | $          | 4.2                    |       | 8.0        |       | $                        | 33.5       |              | $          | 38.6 |   | (13.1 | ) | $ | 49.1 |   | $ | 60.8 |   | (19.2 | ) |
| Other  revenues                                   |       | 0.1                     |       | 0.0        |       | 185.3                  |       | 0.3        |       | 0.1                      |       | 88.4              |       | 0.4 |   | 0.2 |   | 65.3 |   |
| Transportation  revenues*                         |       | 0.7                     |       | 0.6        |       | 40.5                   |       | 2.7        |       | 2.1                      |       | 28.8              |       | 3.5 |   | 2.8 |   | 28.1 |   |
| Total  gas operating revenues                     |       | $                       | 5.4        |       | $          | 4.8                    |       | 12.7       |       | $                        | 36.5       |              | $          | 40.8 |   | (10.6 | ) | $ | 53.0 |   | $ | 63.8 |   | (16.9 | ) |
| Cost  of gas sold                                 |       | 1.6                     |       | 2.0        |       | (23.6                  | )          | 18.9       |       | 25.6                     |       | (25.9             | )          | 29.0 |   | 41.8 |   | (30.6 | ) |
| Gas  operating revenues over cost of gas in rates |       | $                       | 3.8        |       | $          | 2.8                    |       | 39.4       |       | $                        | 17.6       |              | $          | 15.2 |   | 15.1 |   | $ | 24.0 |   | $ | 22.0 |   | 9.2 |   |

 

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**Percentagechange for the twelve  months ended reflectsthe transfer of a customer from transportation to industrial sales in April 2008and back to transportation in April 2009 and percentage change for thenine and twelve months ended reflect a customer switching from industrial salesto transportation in October 2009 after an eight-month suspension.*

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

 

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

 

**Operating Revenues and bcf Sales**

 

Total gas retail bcf salesdecreased during the third quarter of 2010 as compared to 2009. Residential andcommercial bcf sales decreased during the period primarily due to customercontraction. Gas bcf sales are less during the summer months as the heatingseason runs from November to March of each year.

 

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During the third quarter of2010, gas segment revenues were approximately $5.4 million as compared to $4.8million in the third quarter of 2009, an increase of 12.7%. During the thirdquarter of 2010, our PGA revenue (whichrepresents the cost of gas recovered from our customers) wasapproximately $1.6 million as compared to $2.0 million in the third quarter of2009, a decrease of approximately $0.4 million, reflecting the decrease insales and reduced gas costs in PGA revenue. Total retail sales decreased 12.9%while the corresponding revenues increased 8.0%, reflecting the April 2010rate change that caused a greater allocation of margin to be shifted into thecustomer charge and less to sales volumes.

 

Our PGA clause allows us torecover from our customers, subject to routine regulatory review, the cost ofpurchased gas supplies, transportation and storage, including costs associatedwith the use of financial instruments to hedge the purchase price of naturalgas. Pursuant to the provisions of the PGA clause, the difference betweenactual costs incurred and costs recovered through the application of the PGAare reflected as a regulatory asset or regulatory liability until the balanceis recovered from or credited to customers. As of September 30, 2010, wehad unrecovered purchased gas costs of $0.2 million recorded as a regulatoryasset and over-recovered purchased gas costs of $0.7 million recorded as aregulatory liability. On October 19, 2010, we filed a request with theMPSC for a decrease in the PGA for our gas customers. On October 27, 2010,an order was issued approving the PGA rates, effective November 2, 2010.

 

**OperatingRevenue Deductions**

 

Total other operatingexpenses were approximately $2.1 million during the third quarter of 2010 ascompared to $2.3 million in the third quarter of 2009 mainly due to a $0.2million decrease in employee pension expense.

 

Our gas segment had a netloss of $0.4 million for the third quarter of 2010 as compared to a net loss of$1.0 million for the third quarter of 2009. These losses are not unexpected dueto the seasonality of the gas segment whose heating season runs from November toMarch of each year.

 

***Nine Months Ended September 30, 2010 Comparedto Nine Months Ended September 30, 2009***

 

**Operating Revenues and bcf Sales**

 

Gas retail bcf salesincreased 0.7% during the nine months ended September 30, 2010, ascompared to the same period in 2009 mainly due to colder weather in the firstquarter of 2010. Residential and commercial bcf sales increased during the ninemonths ended September 30, 2010, as compared to the same period in 2009primarily due to the colder weather. Industrial bcf sales decreased during thenine months ended September 30, 2010, as compared to the same period in2009 mainly due to the switching ofcustomers between industrial sales and transportation and the suspensionof operations of a large volume sales customer (see footnote above).

 

During the nine months endedSeptember 30, 2010, gas segment revenues were approximately $36.5 millionas compared to $40.8 million in the nine months ended September 30, 2009,a decrease of $4.3 million. This decrease was largely driven by lower PGAs thatwent into effect May 15, 2009 and November 13, 2009. During the ninemonths ended September 30, 2010, our PGA revenue was approximately $18.9million as compared to $25.6 million during the nine months ended September 30,2008, a decrease of approximately $6.6 million.

 

**OperatingRevenue Deductions**

 

Totalother operating expenses were $7.1 million for the nine months ended September 30,2010, as compared to $7.8 million for the nine months ended September 30,2009. This decrease was mainly due to a $0.5 million decrease in employeepension expense, partially offset by a $0.2 million increase in customeraccounts expense.

 

Ourgas segment had net income of $1.6 million for the nine months ended September 30,2010, as compared to a net loss of less than $0.1 million for the nine monthsended September 30,

 

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2009,mainly due to colder than normal weather in the first quarter of 2010 and rateincreases effective April 1, 2010.

 

***Twelve Months Ended September 30, 2010Compared to Twelve Months Ended September 30, 2009***

 

**Operating Revenues and bcf Sales**

 

Gas retail bcf salesdecreased 5.0% during the twelve months ended September 30, 2010, mainlydue to the switching of customersbetween industrial sales and transportation, the suspension ofoperations of a large volume sales customer (see footnote above), and the effect of our gas segment customer contraction of 0.72% for the twelvemonths ended September 30, 2010. We believe this contraction was due to depressed economic conditions. Weestimate that the rate of gas customer contraction will level out during thenext three years and begin modest growth after 2012. Residential andcommercial bcf sales increased during the twelve months ended September 30,2010, primarily due to colder weather in the first quarter of 2010.

 

During the twelve monthsended September 30, 2010, gas segment revenues were approximately $53.0million as compared to $63.8 million in the twelve months ended September 30,2009, a decrease of $10.8 million. This decrease was largely driven by adecrease in the PGAs that went into effect May 15, 2009 and November 13,2009. During the twelve months ended September 30, 2010, our PGA revenuewas approximately $29.0 million as compared to $41.8 million during the twelvemonths ended September 30, 2009, a decrease of approximately $12.8million.

 

**OperatingRevenue Deductions**

 

Totalother operating expenses were $9.6 million for the twelve months ended September 30,2010, as compared to $10.2 million for the twelve months ended September 30,2009. This decrease was mainly due to a $0.5 million decrease in employeepension expense and a $0.1 million decrease in transmission operation expense.

 

Ourgas segment had net income of $2.5 million for the twelve months ended September 30,2010, as compared to $1.1 million for the twelve months ended September 30,2009, mainly due to colder than normal weather in the first quarter of 2010 andrate increases effective April 1, 2010.

 

***Consolidated Company***

 

**Income Taxes**

 

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

 
| ** **                              | ** ** | **Three Months Ended** | ** ** | **Nine-Months Ended** | ** ** | **Twelve Months Ended** | ** ** |
|-----------------------------------------|------------|----------------------------------|------------|----------------------------|------------|-----------------------------------|------------|
| Consolidated provision for income taxes |       | $5.0                             |       | $9.8                       |       | $8.7                              |       |

 

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

 
| ** **                                                 | ** ** | **Three Months Ended** | ** ** | **Nine Months Ended** | ** ** | **Twelve Months Ended** | ** ** |
|------------------------------------------------------------|------------|----------------------------------|------------|---------------------------------|------------|-----------------------------------|------------|
| ** **                                                 | ** ** | **2010**                         | ** ** | **2009**                        | ** ** | **2010**                          | ** ** | **2009** | ** ** | **2010** | ** ** | **2009** | ** ** |
| Consolidated effective federal and state income  tax rates |       | 34.2%                            |       | 31.7%                           |       | 40.4%                             |       | 33.1% |   | 38.8% |   | 33.1% |   |

 

The effective tax rates for the nine months ended September 30,2010, and the twelve months ended September 30, 2010, are higher thancomparable year periods primarily due to the new health care legislation. On March 23,2010, the Patient Protection and Affordable Care Act became law. Thislegislation includes a provision that reduces the deductibility, for income tax

 

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purposes,of retiree healthcare costs to the extent an employer receives federalsubsidies. Companies receive the subsidy when they provide retiree prescriptionbenefits at least equivalent to Medicare Part D coverage in theirpostretirement healthcare plan. Although the elimination of this tax benefitdoes not take effect until 2013, this change requires us to recognize the fullaccounting impact in our financial statements in the period in which thelegislation is enacted. As a result, in the first quarter of 2010, we recordeda one-time non-cash charge of approximately $2.1 million to income taxes toreflect the impact of this change. The change in deductibility will increaseour effective tax rate slightly during the remainder of 2010. Our 2010effective tax rate also increased due to the additional tax expense associatedwith the current year retiree health care accruals.

 

ADecember 2009 award from an arbitration panel ordered KCP&L torenegotiate with the IRS a previous $125 million advanced coal investment taxcredit granted to our Iatan 2 plant. The IRS executed a revised memorandum ofunderstanding (MOU) on September 7, 2010, which granted us our share,$17.7 million, of advanced coal investment tax credits in accordance with thearbitration panel’s order. We will utilize these credits to reduce our 2010 taxpayments and 2010 tax liability and these are reflected as a reduction toaccrued taxes. The tax credit will have no significant income statement impactas the credits will flow to our customers as we amortize the tax credits overthe life of the plant.

 

On September 16, 2010, we received approximately $26.6 millionfrom the SWPA as payment regarding the decrease in available head waters at ourhydroelectric generating plant located on the White River at Ozark Beach,Missouri. Currently, we have increased our current liability for income taxesby $8.3 million in anticipation that we will pay income taxes on the $26.6million award, but no impact to our revenues or net income has been recorded todate. However, we may ultimately defer payment of the taxes if we determinethat certain sections of the Internal Revenue Code allow such treatment. SeeNote 12 of “Notes to Consolidated Financial Statements”.

 

As part of an agreementreached in our most recently completed Missouri electric rate case, effective September 10,2010, we agreed to commence an eighteen year amortization of a deferred assetrelated to the tax benefits of cost of removal. These tax benefits were flowedthrough to customers from 1981-2008 and totaled approximately $11.1 million. Werecorded a regulatory asset expecting to recover these benefits from customersin future periods. We estimated the portion of the amortization period whererate recovery would no longer be probable for this item and wrote offapproximately $1.2 million in the first quarter of 2010. Amortization of theremaining regulatory tax asset will begin in 2012, which is also when we expectto be able to request rate recovery of the asset.

 

**Nonoperating Items**

 

The following table shows the total allowance forfunds used during construction (AFUDC) for the applicable periods ended September 30.Total AFUDC was flat for the twelve months ended September 30, 2010, ascompared to the same period in 2009 while the three-month ended and nine-monthended totals decreased in 2010 reflecting the completion of Iatan 2 and thePlum Point Energy Station in August 2010. In addition, we decreased AFUDCby $0.6 million in the third quarter of 2010 for an AFUDC rate true upreflecting lower construction work in progress balances given the in servicestatus of Iatan 2.

 
| ** **                                             | ** ** | **Three Months Ended** | ** ** | **Nine Months Ended** | ** ** | **Twelve Months Ended** | ** ** |
|--------------------------------------------------------|------------|----------------------------------|------------|---------------------------------|------------|-----------------------------------|------------|
| **($ in millions)**                          | ** ** | **2010**                         | ** ** | **2009**                        | ** ** | **2010**                          | ** ** | **2009** | ** ** | **2010** | ** ** | **2009** | ** ** |
| Allowance for equity funds used during  construction   |       | $                                | 0.8        |                            | $          | 1.4                               |       | $ | 4.5 |   | $ | 4.1 |   | $ | 6.6 |   | $ | 5.7 |   |
| Allowance for borrowed funds used during  construction |       | 0.8                              |       | 1.9                             |       | 5.6                               |       | 6.2 |   | 7.3 |   | 8.2 |   |
| Total AFUDC                                            |       | $                                | 1.6        |                            | $          | 3.3                               |       | $ | 10.1 |   | $ | 10.3 |   | $ | 13.9 |   | $ | 13.9 |   |

 

Totalinterest charges on long-term and short-term debt for the applicable periodsended September 30, are shown below. The decrease in long-term debtinterest for the three-month and nine-month periods ended September 30,2010, reflect the redemption of $48.3 million aggregate principal amount of ourSenior Notes, 7.05% Series due 2022, which were redeemed on August 27,

 

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2010,and replaced by $50 million principal amount 5.20% first mortgage bonds issued August 25,2010, and the redemption of 6.5% first mortgage bonds on April 1, 2010,and the redemption of our 8.5% trust preferred securities on June 28,2010, which were replaced by 4.65% first mortgage bonds issued May 28,2010. The increase in long-term debt interest for the twelve months ended September 30,2010, also reflects the interest on $75 million principal amount of firstmortgage bonds we issued March 27, 2009. The decreases in short-term debtinterest for all periods presented primarily reflect lower levels of borrowing.

 
| ** **                           | ** ** | **Interest  Charges  ($ in millions)** | ** ** |
|--------------------------------------|------------|---------------------------------------------|------------|
| ** **                           | ** ** | **Third**                                   | ** ** | **Third** | ** ** | ** ** | ** ** | **9 Months** | ** ** | **9 Months** | ** ** | ** ** | ** ** | **12 Months** | ** ** | **12 Months** | ** ** | ** ** | ** ** |
| ** **                           | ** ** | **Quarter**                                 | ** ** | **Quarter** | ** ** | **%** | ** ** | **Ended** | ** ** | **Ended** | ** ** | **%** | ** ** | **Ended** | ** ** | **Ended** | ** ** | **%** | ** ** |
| ** **                           | ** ** | **2010**                                    | ** ** | **2009** | ** ** | **Change*** | ** ** | **2010** | ** ** | **2009** | ** ** | **Change*** | ** ** | **2010** | ** ** | **2009** | ** ** | **Change*** | ** ** |
| Long-term  debt interest             |       | $                                           | 10.8       |   | $ | 10.9 |   | (1.4 | )% | $ | 31.3 |   | $ | 31.4 |   | (0.4 | )% | $ | 42.0 |   | $ | 41.0 |   | 2.3 | % |
| Short-term  debt interest            |       | 0.1                                         |       | 0.2 |   | (41.2 | ) | 0.6 |   | 1.0 |   | (38.4 | ) | 0.7 |   | 1.7 |   | (57.2 | ) |
| Trust  preferred securities interest |       | —                                      |       | 1.1 |   | (100.0 | ) | 2.1 |   | 3.2 |   | (34.4 | ) | 3.2 |   | 4.3 |   | (25.8 | ) |
| Iatan  1 and 2 carrying charges      |       | (0.8                                        | )          | (0.3 | ) | 153.9 |   | (1.9 | ) | (0.9 | ) | 112.4 |   | (2.4 | ) | (0.9 | ) | 159.6 |   |
| Other  interest                      |       | 0.2                                         |       | 0.1 |   | 13.7 |   | 0.6 |   | 0.5 |   | 35.3 |   | 0.8 |   | 0.8 |   | 12.1 |   |
| Total  interest charges              |       | $                                           | 10.3       |   | $ | 12.0 |   | (14.4 | ) | $ | 32.7 |   | $ | 35.2 |   | (7.0 | ) | $ | 44.3 |   | $ | 46.9 |   | (5.4 | ) |

 

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**Beginning in the second quarter of 2009, we deferred Iatan 1 carryingcharges in accordance with our agreement with the MPSC that allows deferral ofcertain costs until the environmental upgrades to Iatan 1 are included in ourrate base. We began deferring Iatan 2 carrying charges in the third quarter of2010.*

 

**RATE MATTERS**

 

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

 

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

 

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

 
| **Jurisdiction**         | ** ** | **Date Requested** | ** ** | **Annual Increase  Granted** | ** ** | **Percent  Increase  Granted** | ** ** | **Date Effective** | ** **              |
|--------------------------|------------|-------------------------|------------|-----------------------------------|------------|--------------------------------|------------|-------------------------|-------------------------|
| Missouri – Electric |       | October 29, 2009   |       | $                                 | 46,800,000 |                           | 13.40      | %                       | September 10, 2010 |   |
| Kansas – Electric   |       | November 4, 2009   |       | $                                 | 2,800,000  |                           | 12.4       | %                       | July 1, 2010       |   |
| Missouri – Gas      |       | June 5, 2009       |       | $                                 | 2,600,000  |                           | 4.37       | %                       | April 1, 2010      |   |
| Missouri – Electric |       | October 1, 2007    |       | $                                 | 22,040,395 |                           | 6.70       | %                       | August 23, 2008    |   |

 

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***Electric Segment***

 

*Missouri*

 

*2010 Rate Case*

 

OnSeptember 28, 2010, we filed a rate increase request with the MPSC for anannual increase in base rates for our Missouri electric customers in the amountof $36.5 million, or 9.2% to recover the Iatan 2 costs and other cost ofservice items not included in the 2009 Missouri rate case (see below).

 

*2009 Rate Case*

 

OnOctober 29, 2009, we filed a request with the MPSC for an annual increasein base rates for our Missouri electric customers in the amount of $68.2million, or 19.6%. This request was primarily designed to allow us to recovercapital expenditures associated with environmental upgrades at Iatan 1 and ourinvestment in new generating units at Iatan 2 and the Plum Point GeneratingStation. As a result of the delay in the Iatan 2 project, however, we agreed tonot seek a permanent increase in this rate case for any costs associated withthe Iatan 2 unit with the exception of that portion of the Iatan common plantneeded to operate Iatan 1.

 

Astipulated agreement was filed on May 12, 2010, calling for an annualincrease of $46.8 million, provided the Plum Point Generating Station met itsin-service criteria by August 15, 2010. If the in-service criteria werenot met by such date, a base rate increase of $33.1 million was stipulated. ThePlum Point Generating Station completed its in-service criteria testing on August 12,2010, with an in-service date of August 13, 2010, thus new rates,providing for the full increase of $46.8 million, were effective September 10,2010. The $46.8 million authorized increase in annual revenues includes $36.8million in base rate revenue and $10 million in regulatory amortization. Theregulatory amortization, which is treated as additional book depreciation forrate-making purposes and is reflected in the financial statements, was grantedto provide additional cash flow through rates. This regulatory amortization isrelated to our investments in facilities and environmental upgrades completedduring the recent construction cycle. As agreed in our regulatory plan, we willuse construction accounting for our Iatan 2 project. See Note 3 and Note 7 of “Notesto Consolidated Financial Statements.” We have also agreed to commence aneighteen year amortization of a deferred asset related to the tax benefits ofcost of removal. These tax benefits were flowed through to customers from 1981to 2008 and totaled approximately $11.1 million. We had previously recorded aregulatory asset expecting to recover these benefits from customers in futureperiods. We estimated the portion of the amortization period where raterecovery would no longer be probable for this item and wrote off approximately$1.2 million in the first quarter of 2010. Amortization of the remainingregulatory tax asset will begin in 2012, which is also when we expect to beable to request rate recovery of the asset. See Note 12 of “Notes toConsolidated Financial Statements”.

 

*2007 Rate Case*

 

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

 

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

 

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Iatan1. The regulatory amortization as a result of this case was approximately $4.5million annually and is recorded as depreciation expense.

 

TheMPSC also authorized a fuel adjustment clause for our Missouri customerseffective September 1, 2008. The MPSC established a base cost for therecovery of fuel and purchased power expenses used to supply energy. The clausepermits the distribution to customers of 95% of the changes in fuel andpurchased power costs above or below the base cost. Off-system sales marginsare also part of the recovery of fuel and purchased power costs. As a result,the off-system sales margin flows back to the customer. Rates related to therecovery of fuel and purchased power costs will be modified twice a yearsubject to the review and approval by the MPSC. In accordance with accountingguidance for regulated activities, 95% of the difference between the actualcost of fuel and purchased power and the base cost of fuel and purchased powerrecovered from our customers is recorded as an adjustment to fuel and purchasedpower expense with a corresponding regulatory asset or a regulatory liability.If the actual fuel and purchased power costs are higher or lower than the basefuel and purchased power costs billed to customers, 95% of these amounts willbe recovered or refunded to our customers when the fuel adjustment clause ismodified.

 

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

 

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

 

On October 2, 2008, the OPC and intervenorsPraxair, Inc. and Explorer Pipeline Company filed Petitions forWrit of Review with the Cole County Circuit Court. These actions wereconsolidated into one proceeding, briefs were filed and the Cole County CircuitCourt heard oral arguments on September 29, 2009. The Cole County CircuitCourt issued a ruling on December 31, 2009, affirming the Commission’sReport and Order. OPC, Praxair and Explorer Pipeline filed appeals with theWestern District Court of Appeals. Explorer Pipeline was dismissed from thepending appeal on October 18, 2010.

 

*2006 Rate Case*

 

In December 2008, the OPC andintervenors Praxair, Inc. and Explorer Pipeline Company filed Petitions forWrit of Review with the Cole County Circuit Court challenging the tariffsresulting from our 2006 Missouri rate case that went into effect January 1,2007. The Cole County Circuit Court issued a ruling on December 8, 2009,affirming the Commission’s Report and Order. OPC, Praxair and Explorer Pipelinefiled appeals with the Western District Court of Appeals. On October 26,2010, the Western District Court of Appeals affirmed the Commission’s Reportand Order.

 

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*Kansas*

 

On November 4, 2009, we filed a request with the KCC for an annualincrease in base rates for our Kansas electric customers in the amount of $5.2million, or 24.6%. This request was primarily to allow us to recover capitalexpenditures associated with environmental upgrades at Iatan 1 completed in2009 and at our Asbury plant completed in 2008 and our investment in newgenerating units at Iatan 2, the Plum Point Generating Station and our Riverton12 unit that went on line in 2007. A stipulated agreement was filed on May 4,2010, and approved by the KCC on June 25, 2010, calling for a $2.8 million, or12.4%, increase in base rates effective July 1, 2010. We will deferdepreciation and operating and maintenance expense on both Plum Point and Iatan2 from their respective in-service dates until the effective date for ratesfrom the next Kansas case, expected to be an abbreviated rate case that will befiled within the next year. These deferrals will be recovered over a 3-5 yearperiod as determined in that next case. We will record AFUDC on all Plum Pointand Iatan 2 capital expenditures incurred after January 31, 2010.

 

*Oklahoma*

 

On March 25, 2010, we requested a capital cost recovery rider (CCRR) atthe Oklahoma Corporation Commission (OCC). The rider was designed to recoverthe carrying costs on our capital investment for generation, transmission anddistribution assets that have been added to the system since our last Oklahomageneral rate case (May 2003), as well as investments made on an ongoing basis.As requested, the operation of the CCRR would have increased our operatingrevenue by approximately $3 million, or approximately 33%, in Oklahoma in aseries of three steps to be followed with a general rate case in 2011. OnAugust 30, 2010, we were granted a two-phase Capital Reliability Rider (CRR) bythe OCC. The first phase of the rider was put into place for Oklahoma customersfor usage on and after September 1, 2010, and results in an overall annual baserevenue increase of approximately $1.5 million, or 15.7%. The second phaseinvolves a base revenue increase to be made effective after Iatan 2 goes intoservice, but not before March 1, 2011. The exact level of the phase 2 increasewill be determined by the actual in-service cost of Iatan 2. In total, the CRRrevenue has been specifically limited by the OCC to an overall annual revenueincrease of $2.6 million, or 27.67% increase. We will file a general rate casewithin six months of the commercial operation date of Iatan 2 to replace theCRR with permanent rates.

 

*Arkansas*

 

OnAugust 19, 2010, we filed a rate increase request with the Arkansas PublicService Commission (APSC) for an annual increase in base rates for our Arkansaselectric customers in the amount of $3.2 million, or 27.3%, to recover costsassociated with environmental upgrades at Iatan 1 and the Asbury Power Plant,and our investment in the new generating units Riverton Unit 12, Iatan 2 and thePlum Point Generating Station. We anticipate that any new rates approved by theAPSC will become effective in the summer of 2011.

 

*FERC*

 

OnMarch 12, 2010, we filed GFR tariffs with the FERC which we propose to beutilized for our wholesale customers. On May 28, 2010, the FERC issued an orderthat conditionally approved our GFR filing subject to refund effective June 1,2010. On June 30, 2010, three of our on-system wholesale customers were grantedintervention in the GFR rate case. Also on May 28, 2010, we filed a notice withthe FERC requesting termination of the current bundled service agreements forour wholesale customers effective July 31, 2010. On July 28, 2010, the FERCissued an order accepting and suspending the proposed terminations for a nominalperiod to become effective July 31, 2010, subject to refund. The FERC’s orderalso consolidated the GFR and termination proceedings. On September 15, 2010,the parties agreed to a settlement in principle and are now working to finalizethe terms of the settlement.

 

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***Gas Segment***

 

OnJune 5, 2009, we filed a request with the MPSC for an annual increase in base ratesfor our Missouri gas customers in the amount of $2.9 million, or 4.9%. In thisfiling, we requested recovery of the ongoing cost of operating and maintainingour 1,200-mile gas distribution system and a return on equity of 11.3%. OnFebruary 24, 2010, the MPSC unanimously approved an agreement among the Officeof the Public Counsel (OPC), the MPSC staff and Empire for an increase of $2.6million. Pursuant to the Agreement, new rates went into effect on April 1,2010.

 

**COMPETITION**

 

***Electric Segment***

 

*SPP-RTO*

 

EnergyImbalance Services:  On February1, 2007, the Southwest Power Pool (SPP) regional transmission organization(RTO) launched its energy imbalance services market (EIS). In general, the SPPRTO EIS market provides real time energy for most participating members withinthe SPP regional footprint. Imbalance energy prices are based on market bidsand status/availability of dispatchable generation and transmission within theSPP market footprint. In addition to energy imbalance service, the SPP RTO performsa real time security-constrained economic dispatch of all generationvoluntarily offered into the EIS market to the market participants to alsoserve the native load.

 

Day-AheadMarket:  The SPP and its members havebeen evaluating the costs and benefits on expanding the EIS market into a fullday ahead energy market with a co-optimized ancillary services market, whichwill include the consolidation of all SPP balancing authorities, includingours, into a single SPP balancing authority. On April 28, 2009, the SPPRegional State Committee (SPP RSC), whose members include state commissionersfrom our four state commissions, and the SPP Board of Directors (SPP BOD)endorsed a cost benefit report that recommended the SPP RTO move forward withthe development of a day-ahead market with unit commitment and co-optimizedancillary services market (Day-Ahead Market) and implement the completeDay-Ahead Market as soon as practical, which is anticipated in late 2013 orearly 2014. As part of the Day-Ahead Market, the SPP RTO will create, prior toimplementation of such market, a single NERC approved balancing authority totake over balancing authority responsibilities for its members, including us,which is expected to provide operational and economic benefits for ourcustomers. The implementation of the Day-Ahead Market will replace the existingEIS market, which to date has, and is expected to continue to, provide benefitsfor our customers.

 

SPP Regional Transmission Development:  On August 15, 2008, the SPP filed with theFERC proposed revisions to its open access transmission pro forma tariff (OATT)to establish a process for including a “balanced portfolio” of economictransmission upgrades in the annual SPP Transmission Expansion Plan. The costof such upgrades will be recovered through a regional rate allocated to SPPmembers based on their load ratio share within SPP’s market area of thebalanced portfolio’s cost. On October 16, 2008, the FERC accepted the balancedportfolio approach, which sets forth the selection process of a group ofprojects and regional cost allocation rules based on projected benefits andallocated costs over a ten year period. The plan will be balanced if theportfolio is cost beneficial for each zone, including ours, within the SPP. Abalanced portfolio could include projects below the 345 kv level (which is thebright line voltage level for projects to be included in the portfolio) toincrease benefits to a particular zone to achieve balance of benefits and costsover the ten year study period. On April 28, 2009, the SPP RSC and the SPP BODapproved the first set of balanced portfolio extra high voltage transmissionprojects to be constructed within the SPP region. The transmission expansionprojects, totaling over $840 million, include projects in Missouri, Kansas,Arkansas, Oklahoma, Nebraska and Texas. We anticipate this set of transmissionexpansion projects will provide long term benefits to our customers. While wedo not project our allocated costs for the balanced portfolio projects to bematerial, we expect that the

 

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costswill be recoverable in future rates. Also on April 28, 2009, the SPP RSC andBOD approved a new report that recommended restructuring of the SPP’s regionalplanning processes, which would establish an integrated planning process forreliability, transmission service and economic transmission projects, based ona new set of planning principles that focus on the construction of a morerobust transmission system large enough in both scale and geography to provideflexibility to meet SPP members’ and customers’ future needs. We will continueto actively participate in the development of these new processes as well ascost allocation and recovery issues with members, prospective customers and thestate commission representatives to the SPP RSC.

 

On October 27, 2009, the SPP BOD endorsed a new transmission costallocation method to replace the existing FERC accepted cost allocation methodfor new transmission facilities needed to continue to reliably and economicallyserve SPP customers, including ours, well into the future. On April 19, 2010,SPP filed revisions to its OATT to adopt a new highway/byway cost allocationmethodology which require SPP BOD approved transmission projects of 300 kV orlarger to be funded by the region at 100%, transmission projects between 100 kVand 300 kV to receive 33% regional funding with individual constructing zonesto pay 67% of those projects built within the zone. For projects under 100kV,the constructing zones would pay 100% of the cost. On May 17, 2010, we filed ajoint protest at the FERC with other SPP members based on our disagreement withthe SPP on the allocation percentages and various other issues. On June 17,2010, the FERC unconditionally approved the new highway/byway cost allocationmethod. We and other members of the SPP filed a Request for Rehearing on July19, 2010. It is uncertain as to when or if the FERC will rule on our Requestfor Rehearing. To date, the SPP’s BOD has approved $1.4 billion inhighway/byway projects to be constructed over the next several years. As theseprojects are constructed, we will be allocated a share of the costs of theprojects pursuant to the FERC accepted cost allocation method. We expect thatthese costs will be recoverable in future rates as they are recognized inhistorical test periods.

 

In a related but separate filing, on May 17, 2010, the SPP filedrevisions to its OATT to incorporate a modified transmission planning process,the Integrated Transmission Plan (ITP) that the SPP will use to determine itsnear and long term transmission needs to meet reliability and provide economicbenefits throughout the SPP region. On June 7, 2010, we made a joint protestfiling at the FERC regarding the ITP filing which expressed our concerns overthe lack of explicit provisions in the SPP OATT to protect SPP customers fromthe approval of transmission projects that may not sufficiently benefit the SPPregion. On July 15, 2010, the FERC issued an order conditionally accepting SPPproposed ITP planning process and tariff provisions to be effective on July 17,2010, and ordered SPP to make a compliance filing by August 15, 2010, on thetiming of ITP business practices and factors to be considered for changing theallocation of costs methods for dual winding high voltage transformers. We andthe other parties to the SPP ITP jointly filed a formal Request for Rehearingat the FERC on the ITP order on August 13, 2010. On September 7, 2010, the FERCgranted our Request For Rehearing to allow additional time for FERC’s furtherconsideration.

 

*FERC Market Power Order*

 

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

 

*Other FERC Activity*

 

OnJune 21, 2007, the FERC issued an Advance Notice of Proposed Rulemaking (ANOPR)on potential reforms to improve operations in organized wholesale power markets,such as the SPP RTO in which we participate. On October 16, 2008, the FERCissued its Final Order on Wholesale

 

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Competitionin Regions with Organized Electric Markets. The Final Order will affect us asit directly affects the SPP RTO. The Final Order addresses four key areas foramending its regulations in Wholesale Competition for RTOs and IndependentSystem Operators (ISOs): (1) demand response and market pricing during periodsof operating reserve shortage; (2) long-term power contracting; (3) marketmonitoring policies; and (4) the responsiveness of RTOs and ISOs tostakeholders and customers. We continue to be involved in the SPP RTO and ourstate commission discussions on compliance of these new rules.

 

OnMay 21, 2009, the FERC issued an order clarifying that, going forward, smallpublic utilities that have been granted waiver of Order No. 889 (Open AccessSame Time Information Systems (OASIS) requirement) and the Standards of Conductfor transmission operations, which includes us, are required to submit anotification filing if there has been a material change in facts that mayaffect the basis on which a public utility’s waiver was premised. The Standardsof Conduct generally govern the communications between our day to daytransmission operations personnel and our day to day wholesale marketing andsales personnel. We submitted our filing on July 13, 2009 in which we statedour belief that continuation of our waiver, issued in 1997 and reaffirmed in2004, was appropriate and reasonable. Based on the May 21, 2009 order, it ispossible that the FERC will revoke our waiver which would impact communicationbetween our transmission and wholesale marketing and sales functions andoperations within our organization. As part of our filing, we sought a twelvemonth extension in order to comply with the Standard of Conduct requirements inthe event the FERC determined that revoking our waiver was appropriate. TheFERC’s decision on this and other Standard of Conduct waiver filings ispending. As of July 19, 2010, we have voluntarily taken steps to allow us tocomply with a FERC order with minimal additional impact.

 

OnJune 17, 2010, FERC issued a Notice of Proposed Rulemaking (NOPR) proposing toamend the transmission planning and cost allocation requirements established inOrder No. 890 to ensure that FERC-jurisdictional services are provided on abasis that is just, reasonable and not unduly discriminatory or preferential.With respect to transmission planning, FERC said that the proposed rule would:(1) provide that local and regional transmission planning processes account fortransmission needs driven by public policy requirements established by state orfederal laws or regulations; (2) improve coordination between neighboringtransmission planning regions with respect to interregional facilities; and (3)remove from FERC-approved tariffs or agreements a right of first refusalcreated by those documents that provides an incumbent transmission providerwith an undue advantage over a non-incumbent transmission developer. Neitherincumbent nor non-incumbent transmission facility developers should, as aresult of a FERC-approved tariff or agreement, receive different treatment in aregional transmission planning process, FERC contended. Further, both shouldshare similar benefits and obligations commensurate with that participation,including the right, consistent with state or local laws or regulations, toconstruct and own a facility that it sponsors in a regional transmissionplanning process and that is selected for inclusion in the regionaltransmission plan. With respect to cost allocation, the proposed rule wouldestablish a closer link between transmission planning processes and costallocation and would require cost allocation methods for intraregional andinterregional transmission facilities to satisfy newly established costallocation principles. We participated in the development of comments by theSPP RTO which were filed at FERC on September 29, 2010. We will continue tomonitor the NOPR as it may affect our existing rights to construct transmissionfacilities in our service territory as well as high voltage transmissionexpansion and cost allocation that will affect our cost of delivery service toour customers.

 

***Gas Segment***

 

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

 

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**LIQUIDITY AND CAPITALRESOURCES**

 

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

 

Ourissuance of various securities, including equity, long-term and short-termdebt, is subject to customary approval or authorization by state and federalregulatory bodies including state public service commissions and the SEC. Weestimate that internally generated funds (funds provided by operatingactivities less dividends paid) will provide only a portion of the fundsrequired in 2010 for our budgeted capital expenditures (as discussed in “CapitalRequirements and Investing Activities” below). We believe the amounts availableto us under our credit facilities and the issuance of debt and equitysecurities together with this cash provided by operating activities will allowus to meet our needs for working capital, pension contributions, our continuingconstruction expenditures, anticipated debt redemptions, interest payments ondebt obligations, dividend payments and other cash needs through the nextseveral years.

 

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

 

**Summaryof Cash Flows**

 
| ** **                              | ** ** | **Nine Months Ended September 30,** | ** **                         |
|-----------------------------------------|------------|-------------------------------------|------------------------------------|
| **(in millions)**                  | ** ** | **2010**                            | ** **                         | **2009** | ** ** |
| Cash provided by/(used in):             |       |                                |                               |   |   |
| Operating activities                    |       | $                                   |    103.7                 |   | $ |    106.9 |   |
| Investing activities                    |       | (81.0                               | )                                  | (116.5 | ) |
| Financing activities                    |       | (13.6                               | )                                  | 12.8 |   |
| Net change in cash and cash equivalents |       | $                                   |       9.1 |   | $ |       3.2 |   |

 

**Cashflow from Operating Activities**

 

Weprepare our statement of cash flows using the indirect method. Under this method,we reconcile net income to cash flows from operating activities by adjustingnet income for those items that impact net income but may not result in actualcash receipts or payments during the period. These reconciling items includedepreciation and amortization, pension costs, deferred income taxes, equityAFUDC, changes in commodity risk management assets and liabilities and changesin the consolidated balance sheet for working capital from the beginning to theend of the period.

 

Period-over-periodchanges in our operating cash flows are attributable primarily to workingcapital changes resulting from the impact of weather, the timing of customercollections, payments for natural gas and coal purchases and the effects ofdeferred fuel recoveries. The increase in natural gas prices directly impactsthe cost of gas stored in inventory. In the third quarter of 2010, we alsoreceived a $26.6 million SWPA payment which positively impacted operating cashflows.

 

*NineMonths Ended September 30, 2010 Compared to 2009**. *During the nine months endedSeptember 30, 2010, our net cash flow provided from operating activities was$103.7 million, a decrease of $3.1 million or 2.9% from 2009. This decrease wasprimarily a result of:

 

·                  Draw down of the commodity risk managementmargin accounts through settlement of hedged positions in 2009 - $(7.6)million.

·                  Changes in seasonal levels of inventory,including the effect of building coal inventories at Plum Point and Iatan 2 -$(6.6) million.

·                  Pension contribution — $(5.7) million

 

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·                  Changes in receivables due to seasonal levelsof trade accounts receivable and unbilled revenues, offset by insuranceproceeds received from the 2009 State Line generator failure - $(9.5) million.

·                  Changes in accrued interest and accrued taxes— $(9.0).

·                  Changes in prepaid expenses and deferredcharges primarily related to changes in deferred fuel costs and non-cashconstruction accounting - $(9.1) million.

·                  One-time payment from SWPA for future minimumflow decreases at Ozark Beach hydro plant - $26.6 million.

·                  Changes in deferred income tax and investmenttax credits, primarily the granting of $17.7 million of advanced coalinvestment tax credits resulting from a revised MOU from the IRS - $12.6million

·                  Changes in net income - $5.6 million.

 

**CapitalRequirements and Investing Activities**

 

Ournet cash flows used in investing activities decreased $35.5 million during thenine months ended September 30, 2010, as compared to the same period in 2009

 

Our capital expenditures incurred totaled approximately $78.9 millionduring the nine months ended September 30, 2010, compared to $120.8 million forthe nine months ended September 30, 2009. The decrease was primarily the resultof a decrease in electric plant additions and replacements, storm expendituresand new generation construction in 2010.

 

A breakdown of the capital expenditures for the nine months endedSeptember 30, 2010 and 2009 is as follows:

 
| ** **                                                   | ** ** | **Capital Expenditures** | ** ** |
|--------------------------------------------------------------|------------|--------------------------|------------|
| **(in millions)**                                       | ** ** | **2010**                 | ** ** | **2009** | ** ** |
| Distribution and transmission system additions               |       | $                        | 25.1       |   | $ | 24.9 |   |
| New Generation — Plum Point Energy Station              |       | 6.6                      |       | 13.3 |   |
| New Generation — Iatan 2                                |       | 38.3                     |       | 49.3 |   |
| Storms                                                       |       | 0.1                      |       | 6.5 |   |
| Additions and replacements — electric plant             |       | 5.0                      |       | 25.8 |   |
| Gas segment additions and replacements                       |       | 1.4                      |       | 1.5 |   |
| Transportation                                               |       | 1.0                      |       | 1.3 |   |
| Other (including retirements and salvage -net) (1)           |       | (0.9                     | )          | (2.8 | ) |
| **Subtotal**                                                 |       | 76.6                     |       | 119.8 |   |
| Non-regulated capital expenditures (primarily  fiber optics) |       | 2.3                      |       | 1.0 |   |
| **Subtotal capital expenditures  incurred (2)**              |       | 78.9                     |       | 120.8 |   |
| Adjusted for capital expenditures payable (3)                |       | 2.2                      |       | 3.7 |   |
| **Total cash outlay**                                        |       | $                        | 81.1       |   | $ | 117.1 |   |

 

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(1)Other includes equity AFUDC of $(4.5) million and $(4.1) million for 2010 and2009, respectively.

(2) Expenditures incurred represent the total cost for work completedfor the projects during the reporting period. Discussion of capital expendituresthroughout this 10-Q is presented on this basis. These capital expendituresinclude AFUDC, capital expenditures to retire assets and benefits from salvage.

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

 

100%of our cash requirements for capital expenditures during the third quarter of2010 were satisfied internally from operations (funds provided by operating activitiesless dividends paid).

 

Weestimate that our capital expenditures for the remainder of 2010 will beapproximately $29.1 million and for 2011 and 2012 will be approximately $106.3million and $127.5 million, respectively, excluding AFUDC. We estimate thatinternally generated funds will provide none of the funds required for theremainder of our budgeted 2010 capital expenditures. We intend to utilize acombination of short-term debt, the proceeds of sales of long-term debt and/orcommon stock (including common stock sold under our Employee Stock PurchasePlan, our Dividend Reinvestment and Stock Purchase Plan, and our 401(k) Planand ESOP) to finance additional amounts needed beyond those provided byoperating activities for such capital expenditures. We will continue to utilizeshort-term debt as needed to support normal operations or other temporary

 

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requirements.For further information see Note 6 of “Notes to Consolidated FinancialStatements (Unaudited).”

 

**FinancingActivities**

 

Ournet cash flows provided by financing activities decreased $26.4 million duringthe first nine months of 2010 as compared to the same period in 2009, resultingin $13.6 million in net cash used in financing activities.

 

OnAugust 25, 2010, we issued $50 million principal amount of 5.20% first mortgagebonds due September 1, 2040. The net proceeds (after payment of expenses) ofapproximately $49.1 million wereused to redeem $48.3 million aggregate principal amount of our Senior Notes,7.05% Series due 2022 on August 27, 2010.

 

OnMay 28, 2010, we issued $100 million principal amount of 4.65% first mortgagebonds due June 1, 2020. The net proceeds (after payment of expenses) ofapproximately $98.8 million, wereused to redeem all 2 million outstanding shares of our 8.5% trust preferredsecurities, totaling $50 million, on June 28, 2010, and to repay short-termdebt which was incurred, in part, to fund the repayment, at maturity, of our6.5% first mortgage bonds due 2010.

 

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

 

Wehad $19 million in short-term debt as of September 30, 2010, versus $44 millionas of September 30, 2009.

 

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.

 

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 September 30, 2010, $55 million remains available forissuance under this shelf registration statement. Of the original $400 million,$250 million was available for first mortgage bonds, of which $25 millionremains available. We expect to file a new shelf registration statement in thenear future to replace this existing one and plan to use a portion of theproceeds from issuances under this shelf (and any new shelf) to fund a portionof the capital expenditures for our new generation projects and to refinancelong-term debt.

 

OnJuly 15, 2005, we entered into a $150 million unsecured revolving creditfacility which was scheduled to terminate on July 15, 2010. On March 14, 2006,we entered into the First Amended and Restated Unsecured Credit Agreement whichamended and restated the $150 million unsecured revolving credit facility. Theprincipal amount of the credit facility was increased to $226 million, with theadditional $76 million allocated to support a letter of credit issued inconnection with our participation in the Plum Point Energy Station project.This extra $76 million of availability reduced over a four year period in linewith the amount of construction expenditures we owed for Plum Point Unit 1 andterminated on July 15, 2010. On January 26, 2010, we entered into the SecondAmended and Restated Unsecured Credit Agreement which amended and restated thisfacility again. This agreement extends the termination date of the revolvingcredit facility from July 15, 2010 to January 26, 2013. In addition, thepricing and fees under the facility were amended. Interest on borrowings underthe facility accrues at a rate equal to, at our option, (i) the highest of (A)the bank’s prime commercial rate, (B) the federal funds effective rate plus0.5% or (C) one month LIBOR plus 1.0%, plus a margin or (ii) one month, twomonth or three month LIBOR, in each case, plus a margin. Each margin is basedon our current credit ratings and the pricing schedule in

 

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thefacility. As of the date hereof, and based on our current credit ratings, theLIBOR margin under the facility increased from 0.80% to 2.70%. A facility feeis payable quarterly on the full amount of the commitments under the facilityand a usage fee is payable on the full amount of the commitments under thefacility for any period in which we have drawn less than 33% of the totalrevolving commitments under the facility, in each case based on our currentcredit ratings. In addition, upon entering into the amended and restatedfacility, we paid an upfront fee to the revolving credit banks of $900,000 inthe aggregate. The aggregate amount of the revolving commitments remainedunchanged at $150 million and there were no other material changes to the termsof the facility.

 

Thefacility is used for working capital, general corporate purposes and to back-upour use of commercial paper. This facility requires our total indebtedness(which does not include our trust preferred securities) to be less than 62.5%of our total capitalization at the end of each fiscal quarter and our EBITDA(defined as net income plus interest, taxes, depreciation and amortization) tobe at least two times our interest charges (which includes interest on thetrust preferred securities) for the trailing four fiscal quarters at the end ofeach fiscal quarter. Failure to maintain these ratios will result in an eventof default under the credit facility and will prohibit us from borrowing fundsthereunder. As of September 30, 2010, we are in compliance with these ratios.This credit facility is also subject to cross-default if we default on inexcess of $10 million in the aggregate on our other indebtedness. Thisarrangement does not serve to legally restrict the use of our cash in thenormal course of operations. There were no outstanding borrowings under thisagreement at September 30, 2010. However, $19.0 million was used to back up ouroutstanding commercial paper.

 

OnMarch 11, 2009, we entered into a $50 million unsecured credit agreement. Thisagreement, which terminated on July 15, 2010, provided for $50 million ofrevolving loans to be available to us for working capital, general corporatepurposes and to back-up our use of commercial paper and was in addition to, andhad substantially identical covenants and terms as (other than pricing) ourSecond Amended and Restated Unsecured Credit Agreement dated January 26, 2010discussed above.

 

Theprincipal amount of all series of first mortgage bonds outstanding at any onetime under the EDE Mortgage is limited by terms of the mortgage to $1 billion.Substantially all of the property, plant and equipment of The Empire DistrictElectric Company (but not its subsidiaries) is subject to the lien of the EDEMortgage.****Restrictions in the EDE mortgage bondindenture could affect our liquidity. The EDE Mortgage contains a requirementthat for new first mortgage bonds to be issued, our net earnings (as defined inthe EDE Mortgage) for any twelve consecutive months within the fifteen monthspreceding issuance must be two times the annual interest requirements (as definedin the EDE Mortgage) on all first mortgage bonds then outstanding and on theprospective issue of new first mortgage bonds. Our earnings for the twelvemonths ended September 30, 2010, would permit us to issue approximately $346.3million of new first mortgage bonds based on this test with an assumed interestrate of 6.0%. In addition to the interest coverage requirement, the EDEMortgage provides that new bonds must be issued against, among other things,retired bonds or 60% of net property additions. At September 30, 2010, we hadretired bonds and net property additions which would enable the issuance of atleast $624.4 million principal amount of bonds if the annual interestrequirements are met. As of September 30, 2010, we are in compliance with all restrictivecovenants 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

 

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quartersis at least 2.0 to 1.****As ofSeptember 30, 2010, this test would allow us to issue approximately $5.7million principal amount of new first mortgage bonds.

 

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

 
| ** **               | ** ** | **Fitch** | ** ** | **Moody’s** | ** ** | **Standard & Poor’s** |
|--------------------------|------------|-----------|------------|------------------|------------|------------------------------------------|
| Corporate  Credit Rating |       | n/r*      |       | Baa2             |       | BBB-                                     |
| First  Mortgage Bonds    |       | BBB+      |       | A3               |       | BBB+                                     |
| Senior  Notes            |       | BBB       |       | Baa2             |       | BBB-                                     |
| Commercial  Paper        |       | F2        |       | P-2              |       | A-3                                      |
| Outlook                  |       | Stable    |       | Stable           |       | Stable                                   |

 

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*Notrated

 

OnMarch 24, 2010, Standard & Poor’s issued a report with our ratingsunchanged and upgraded our business profile to “excellent” from “strong”. On May14, 2010, Moody’s upgraded our First Mortgage Bonds from Baa1 to A3 andupgraded its outlook from negative to stable. Moody’s affirmed all of our otherratings. On April 1, 2010, Fitch affirmed our ratings and revised their ratingoutlook to stable. The revision took into consideration the anticipatedcompletion of our five-year baseload capital expenditure program in 2010 andassumes we will receive timely and adequate regulatory recovery of newlycompleted investments.

 

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

 

**CONTRACTUAL OBLIGATIONS**

 

Materialchanges to our contractual obligations at September 30, 2010, compared toDecember 31, 2009 consist of the following:

 

·                  We issued $100 million principal amount of4.65% first mortgage bonds on May 28, 2010, which are due June 1, 2020 andrequire semi-annual interest payments of $2.3 million. Funds from this offeringwere used in part to refinance $50 million of 8.5% Trust Preferred Securitieson June 28, 2010, that were originally due 2031 and required quarterly interestpayments totaling $4.3 million each year. The proceeds were also used to repayshort-term debt which was incurred, in part, to fund the repayment of $50million of 6.5% first mortgage bonds which matured April 1, 2010.

 

·                  We also entered into a contract in the secondquarter of 2010 for the transportation of coal beginning June 30, 2010, whichreplaced a contract that expired June 29, 2010. The contract term is for sixand one-half years and the minimum payments total approximately $91.9 millionover the term of the contract. Minimum payments under this contract are asfollows:

 
|   | 2010  - $7.9 million                 |
|--------|--------------------------------------|
|   | 2011-2012  - $28.0 million           |
|   | 2013-2014  - $28.0 million           |
|   | 2015  and thereafter - $28.0 million |

 

·                  In the third quarter, we issued $50 millionprincipal amount of 5.20% first mortgage bonds on August 25, 2010, which aredue September 1, 2040, and require semi-annual interest payments of $1.3million. Funds from this offering were used to redeem $48.3 million of 7.05%Series Senior Notes that were due in 2022 which required quarterly interestpayments of $0.9 million.

 

**DIVIDENDS**

 

Holdersof our common stock are entitled to dividends if, as, and when declared by theBoard of Directors, out of funds legally available therefore, subject to theprior rights of holders of any outstanding cumulative preferred stock andpreference stock. Payment of dividends is determined by our Board of Directorsafter considering all relevant factors, including the amount of our retained earnings(which is essentially our accumulated net income less dividend payouts). As

 

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ofSeptember 30, 2010, our retained earnings balance was $10.3 million, comparedto $10.1 million as of December 31, 2009, after paying out $38.7 million individends during the first nine months of 2010. A reduction of our dividend pershare, partially or in whole, could have an adverse effect on our common stockprice. On October 28, 2010, the Board of Directors declared a quarterlydividend of $0.32 per share on common stock payable December 15, 2010, toholders of record as of December 1, 2010.

 

Our diluted earnings pershare were $0.97 for the nine months ended September 30, 2010, and were $1.18and $1.17 for the years ended December 31, 2009 and 2008, respectively.Dividends paid per share were $0.96 for the nine months ended September 30,2010, and $1.28 for each of the years ended December 31, 2009 and 2008.

 

UnderKansas corporate law, our Board of Directors may only declare and pay dividendsout of our surplus or, if there is no surplus, out of our net profits for thefiscal year in which the dividend is declared or the preceding fiscal year, orboth. Our surplus, under Kansas law, is equal to our retained earnings plusaccumulated other comprehensive income/(loss), net of income tax. However,Kansas law does permit, under certain circumstances, our Board of Directors totransfer amounts from capital in excess of par value to surplus. In addition,Section 305(a) of the Federal Power Act (FPA) prohibits the payment by autility of dividends from any funds “properly included in capital account”.There are no additional rules or regulations issued by the FERC under the FPAclarifying the meaning of this limitation. However, several decisions by theFERC on specific dividend proposals suggest that any determination would bebased on a fact-intensive analysis of the specific facts and circumstancessurrounding the utility and the dividend in question, with particular focus onthe impact of the proposed dividend on the liquidity and financial condition ofthe utility.

 

Inaddition, the EDE Mortgage and our Restated Articles contain certain dividendrestrictions. The most restrictive of these is contained in the EDE Mortgage,which provides that we may not declare or pay any dividends (other thandividends payable in shares of our common stock) or make any other distributionon, or purchase (other than with the proceeds of additional common stockfinancing) any shares of, our common stock if the cumulative aggregate amountthereof after August 31, 1944 (exclusive of the first quarterly dividend of $98,000paid after said date) would exceed the sum of $10.75 million and the earnedsurplus (as defined in the EDE Mortgage) accumulated subsequent to August 31,1944, or the date of succession in the event that another corporation succeedsto our rights and liabilities by a merger or consolidation. On March 11, 2008,we amended the EDE Mortgage in order to provide us with more flexibility to paydividends to our shareholders by increasing the basket available to paydividends by $10.75 million, as described above. As of September 30, 2010, thisrestriction did not prevent us from issuing dividends.

 

**OFF-BALANCE SHEET ARRANGEMENTS**

 

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

 

**CRITICAL ACCOUNTING POLICIES**

 

See“Item 7 — Management’s Discussion and Analysis of Financial Condition andResults of Operations” in our Annual Report Form 10-K for the year endedDecember 31, 2009 for a discussion of additional critical accounting policies.There were no changes in these policies in the quarter ended September 30,2010.

 

**RECENTLY ISSUED ACCOUNTING STANDARDS**

 

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

 

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**Item 3.  Quantitative andQualitative Disclosures about Market Risk**

 

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

 

*Market Risk and Hedging Activities.*

 

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

 

We engage in physical and financial trading activities with the goalsof reducing risk from market fluctuations. In accordance with our establishedEnergy Risk Management Policy, which typically includes entering into variousderivative transactions, we attempt to mitigate our commodity market risk.Derivatives are utilized to manage our gas commodity market risk and to helpmanage our exposure resulting from purchasing most of our natural gas on thevolatile spot market for the generation of power for our native-load customers.See Note 4 of “Notes to Consolidated Financial Statements (Unaudited)” forfurther information.

 

*Commodity Price Risk*.

 

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

 

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

 

We are exposed to changes in market prices for natural gas we mustpurchase to run our combustion turbine generators. Our natural gas procurementprogram is designed to manage our costs to avoid volatile natural gas prices.We enter into physical forward and financial derivative contracts withcounterparties relating to our future natural gas requirements that lock inprices (with respect to predetermined percentages of our expected futurenatural gas needs) in an attempt to lessen the volatility in our fuelexpenditures and improve predictability. As of October 22, 2010, 55%, or 0.7million Dths, of our anticipated volume of natural gas usage for our electric operationsfor the remainder of 2010 is hedged.

 

Basedon our expected natural gas purchases for our electric operations for the nexttwelve months, if average natural gas prices should increase 10% more than theprice at September 30, 2010, our natural gas cost would increase byapproximately $0.5 million based on our September 30, 2010, total hedgedpositions for the next twelve months. However, this is probable of recoverythrough fuel adjustment mechanisms. We have a fuel cost recovery mechanism inall of our jurisdictions, which significantly reduces the impact of fluctuatingfuel costs.

 

Weattempt to mitigate a portion of our natural gas price risk associated with ourgas segment using physical forward purchase agreements, storage and derivativecontracts. As of September 30, 2010, we have 1.8 million Dths in storage on thethree pipelines that serve our customers. This represents 88% of our storagecapacity. Our long-term hedge strategyis to mitigate price volatility for our customers by hedging a minimum of 50%of the current year, up to 50% of the second year and up to 20% of third yearexpected gas usage by the beginning of the ACA year at September 1. However, due to purchased natural gas costrecovery mechanisms for our retail customers, fluctuations in the cost ofnatural gas have little effect on income.

 

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*CreditRisk*.

 

Inorder to minimize overall credit risk, we maintain credit policies, includingthe evaluation of counterparty financial condition and the use of standardizedagreements that facilitate the netting of cash flows associated with a singlecounterparty. See Note 4 of “Notes to Consolidated Financial Statements(Unaudited)” regarding agreements containing credit risk contingent features.In addition, certain counterparties make available collateral in the form ofcash held as margin deposits as a result of exceeding agreed-upon creditexposure thresholds or may be required to prepay the transaction. Conversely,we are required to post collateral with counterparties at certain thresholds,which is typically the result of changes in commodity prices. Amounts reportedas margin deposit liabilities represent counterparty funds we hold that resultfrom various trading counterparties exceeding agreed-upon credit exposurethresholds. Amounts reported as margin deposit assets represent our funds heldon deposit for our NYMEX contracts with our broker and other financialcontracts with other counterparties that resulted from us exceeding agreed-uponcredit limits established by the counterparties. The following table depictsour margin deposit assets at September 30, 2010 and December 31, 2009. There wereno margin deposit liabilities at these dates.

 
| **(in millions)** | ** ** | **September 30, 2010** | ** ** | ** December 31, 2009** | ** ** |
|------------------------|------------|----------------------------------|------------|---------------------------------------|------------|
| Margin deposit assets  |       | $                                | 3.6        |                                  | $          | 2.9 |   |
|                        |            |                                  |            |                                       |            |  |  |

 

Ourexposure to credit risk is concentrated primarily within our fuel procurementprocess, as we transact with a smaller, less diverse group of counterpartiesand transactions may involve large notional volumes and potentially volatilecommodity prices. Below is a table showing our net credit exposure at September30, 2010, reflecting that our counterparties are exposed to Empire for the netunrealized mark-to-market losses for physical forward and financial natural gascontracts carried at fair value.

 
| **(in millions)**                                                           | ** ** | ** ** | ** ** |
|----------------------------------------------------------------------------------|------------|------------|------------|
| Net unrealized mark-to-market losses for physical  forward natural gas contracts |       | $          | 18.5       |   |
| Net unrealized mark-to-market losses for financial  natural gas contracts        |       | 5.1        |       |
| **Net credit exposure**                                                          | ** ** | **$**      | **23.6**   | ** ** |

 

The$5.1 million net unrealized mark-to-market loss for financial natural gascontracts is comprised of $5.1 million that our counterparties are exposed toEmpire for unrealized losses and there are no unrealized gains from ourcounterparties. We are holding no collateral from any counterparty since we arebelow the $10 million mark-to-market collateral threshold in our agreements. Asnoted above, as of September 30, 2010, we have $3.6 million on deposit forNYMEX contract exposure to Empire, of which $3.5 million represents ourcollateral requirement. In addition, ifNYMEX gas prices decreased 25% from their September 30, 2010, levels, we wouldbe required to post an additional $3.4 million in collateral. If these pricesincreased 25%, our collateral requirement would decrease $1.8 million. Ourother counterparties would not be required to post collateral with Empire.

 

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

 

*Interest Rate Risk.*

 

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

 

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

 

**Item 4.   Controls andProcedures**

 

Asof the end of the period covered by this report, an evaluation was carried out,under the supervision and with the participation of our management, includingour Chief Executive Officer and Chief Financial Officer, of the effectivenessof the design and operation of our disclosure controls and procedures (as suchterm is defined in Rule 13a-15(e) of the Securities Exchange Act of 1934).Based upon that evaluation, the Chief Executive Officer and Chief FinancialOfficer concluded that our disclosure controls and procedures were effective asof September 30, 2010.

 

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

 

**PART II.  OTHER INFORMATION**

 

**Item 1.  Legal Proceedings**

 

***Platte County Levee Lawsuit***

 

OnMay 22, 2009, a suit was filed in the Circuit Court of Platte County Missouriby several individuals and Class Representatives alleging damages to land,structures, equipment and devastation of Plaintiff crops due to inappropriatemanagement of the levee system around Iatan, of which we are 12% owners. No proceduralschedule has been established and we are unable to predict the outcome of thelaw suit.

 

**Item 1A.  Risk Factors.**

 

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

 

**Item5.  Other Information.**

 

Forthe twelve months ended September 30, 2010, our ratio of earnings to fixedcharges was 2.53x.  See Exhibit (12)hereto.

 

**Item 6.  Exhibits.**

 

(a)                                 Exhibits.

 

(4)Thirty-Sixth Supplemental Indenture, dated as of August 25, 2010, to theIndenture of Mortgage and Deed of Trust dated as of September 1, 1944, asamended and supplemented, among the Company, The Bank of New York Mellon TrustCompany, N.A. and UMB Bank & Trust, N.A. (Incorporated by reference toExhibit 4.1 to Current Report on Form 8-K dated August 25, 2010, and filedAugust 26, 2010, File No. 1-3368).

 

(12)Computation of Ratio of Earnings to Fixed Charges.

 

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(31)(a)Certification of Chief Executive Officer pursuant to Section 302 of theSarbanes-Oxley Act of 2002.

 

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

 

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

 

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

 

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*****Thiscertification accompanies this Report pursuant to Section 906 of theSarbanes-Oxley Act of 2002 and shall not be deemed filed by the Company forpurposes of Section 18 or any other provision of the Securities Exchange Act of1934, 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 8, 2010

 

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