10-Q

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)

xQuarterly report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the quarterly period ended March 31, 2006 or

oTransition 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 its charter)

Kansas	44-0236370
(State of Incorporation)	(I.R.S. Employer Identification No.)
602 Joplin Street, 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 all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.   Yes x   No o

Indicate by check mark if the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Act. (Check one):

Large accelerated filer   o Accelerated filer   x Non-accelerated filer   o

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

As of May 1, 2006, 26,186,954 shares of common stock were outstanding.

THE EMPIRE DISTRICT ELECTRIC COMPANY

INDEX

	Forward Looking Statements
Part I -	Financial Information (Unaudited):
Item 1.	Consolidated Financial Statements:
	a.Consolidated Statements of Operations
	b.Consolidated Statements of Comprehensive Income
	c.Consolidated Balance Sheets
	d.Consolidated Statements of Cash Flows
	e.Notes to Consolidated Financial Statements
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations
	Executive Summary
	Results of Operations
	Liquidity and Capital Resources
	Contractual Obligations
	Dividends
	Off-Balance Sheet Arrangements
	Critical Accounting Policies
	Recently Issued Accounting Standards
Item 3.	Quantitative and Qualitative Disclosures About Market Risk
Item 4.	Controls and Procedures
Part II-	Other Information:
Item 1.	Legal Proceedings - (none)
Item 1A.	Risk Factors
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds - (none)
Item 3.	Defaults Upon Senior Securities - (none)
Item 4.	Submission of Matters to a Vote of Security Holders
Item 5.	Other Information
Item 6.	Exhibits
Signatures

2

FORWARD LOOKING STATEMENTS

Certain matters discussed in this quarterly report are “forward-looking statements” intended to qualify for the safe harbor from liability established by the Private Securities Litigation Reform Act of 1995. Such statements address or may address future plans, objectives, expectations and events or conditions concerning various matters such as capital expenditures, earnings, pension and other costs, competition, litigation, our construction program, our generation plans, our financing plans, potential acquisitions, rate and other regulatory matters, 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 as forward-looking statements. Factors that could cause actual results to differ materially from those currently anticipated in such statements include:

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

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

·weather, business and economic conditions and other factors which may impact customer growth;

·operation of our generation facilities;

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

·legislation;

·regulation, including environmental regulation (such as NOx regulation);

·competition, including the launch of the energy imbalance market;

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

·the impact of deregulation on off-system sales;

·changes in accounting requirements;

·other circumstances affecting anticipated rates, revenues and costs, including pension and post-retirement costs;

·the timing of, accretion estimates, and integration costs relating to, contemplated acquisitions and the performance of acquired businesses;

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

·the performance and liquidity needs of our non-regulated businesses;

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

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

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

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

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PART I. FINANCIAL INFORMATION

Item 1. Consolidated Financial Statements

THE EMPIRE DISTRICT ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)

	Three Months Ended
	March 31,
	2006			2005
	(000’s except per share amounts)
Operating revenues:
Electric	$	82,642		$	73,235
Water	369			321
Non-regulated	4,918			5,979
	87,929			79,535
Operating revenue deductions:
Fuel	20,879			22,751
Purchased power	19,928			12,115
Regulated — other	12,869			14,135
Non-regulated — other	5,120			6,135
Maintenance and repairs	5,210			4,800
Depreciation and amortization	9,446			7,953
Provision/(Benefit) for income taxes	843			(95		)
Other taxes	4,785			4,575
	79,080			72,369
Operating income	8,849			7,166
Other income and (deductions):
Allowance for equity funds used during construction	125			20
Interest income	86			68
Provision for other income taxes	12			36
Minority interest	30			(27		)
Other - non-operating expense	(205		)	(213		)
	48			(116		)
Interest charges:
Long-term debt	5,967			6,152
Note payable to securitization trust	1,063			1,063
Short-term debt	376			—
Allowance for borrowed funds used during construction	(385		)	(34		)
Other	264			119
	7,285			7,300
Net income (loss)	$	1,612		$	(250	)
Weighted average number of common shares outstanding — basic	26,133			25,742
Weighted average number of common shares outstanding — diluted	26,153			25,742
Earnings (loss) per weighted average share of common stock — basic	$	0.06		$	(0.01	)
Earnings (loss) per weighted average share of common stock — diluted	$	0.06		$	(0.01	)
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 OPERATIONS (UNAUDITED)

	Twelve Months Ended
	2006			2005
	(000’s except per share amounts)
Operating revenues:
Electric	$	368,049		$	304,089
Water	1,494			1,354
Non-regulated	25,011			22,400
	394,554			327,843
Operating revenue deductions:
Fuel	110,884			70,096
Purchased power	60,532			50,894
Regulated — other	52,901			53,433
Non-regulated — other	24,381			23,806
Maintenance and repairs	21,285			20,411
Depreciation and amortization	37,164			31,179
Provision for income taxes	12,948			10,101
Other taxes	19,615			18,222
	339,710			278,142
Operating income	54,844			49,701
Other income and (deductions):
Allowance for equity funds used during construction	410			142
Interest income	359			255
Provision for other income taxes	87			(256		)
Minority interest	(287		)	239
Other - non-operating income	5			67
Other - non-operating expense	(948		)	(948		)
	(374		)	(501		)
Interest charges:
Long-term debt	23,875			24,633
Note payable to securitization trust	4,250			4,250
Short-term debt	571			12
Allowance for borrowed funds used during construction	(606		)	(120		)
Other	750			405
	28,840			29,180
Net income	$	25,630		$	20,020
Weighted average number of common shares outstanding — basic	25,995			25,581
Weighted average number of common shares outstanding — diluted	26,017			25,627
Earnings per weighted average share of common stock — basic	$	0.99		$	0.78
Earnings per weighted average share of common stock — diluted	$	0.99		$	0.78
Dividends per share of common stock	$	1.28		$	1.28

See accompanying Notes to Consolidated Financial Statements.

5

THE EMPIRE DISTRICT ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	Three Months Ended
	March 31,
	2006			2005
	($-000’s)
Net income (loss)	$	1,612		$	(250	)
Reclassification adjustments for gains included in net income or reclassified to regulatory asset or liability	(936		)	(13		)
Net change in fair market value of open derivative contracts for period	(6,024		)	11,840
Income taxes	2,652			(4,494		)
Net change in unrealized (loss)/gain on derivative contracts	(4,308		)	7,333
Comprehensive income	$	(2,696	)	$	7,083

	Twelve Months Ended
	March 31,
	2006			2005
	($-000’s)
Net income	$	25,630		$	20,020
Reclassification adjustments for gains included in net income or reclassified to regulatory asset or liability	(3,888		)	(8,547		)
Net change in fair market value of open derivative contracts for period	9,753			13,607
Income taxes	(2,251		)	(1,923		)
Net change in unrealized gain on derivative contracts	3,614			3,137
Comprehensive income	$	29,244		$	23,157

See accompanying Notes to Consolidated Financial Statements

6

THE EMPIRE DISTRICT ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEETS (UNAUDITED)

	March 31, 2006		December 31, 2005
	($-000’s)
Assets
Plant and property, at original cost:
Electric	$	1,266,178	$	1,253,664
Water	9,830		9,731
Non-regulated	26,493		26,227
Construction work in progress	52,030		37,495
	1,354,531		1,327,117
Accumulated depreciation and amortization	438,296		431,084
	916,235		896,033
Current assets:
Cash and cash equivalents	3,408		15,974
Accounts receivable — trade, net of allowance of $592 and $515, respectively	26,321		30,622
Accrued unbilled revenues	3,573		6,502
Accounts receivable — other	12,980		19,297
Fuel, materials and supplies	37,207		33,790
Unrealized gain in fair value of derivative contracts	4,369		7,644
Prepaid expenses	2,367		2,200
	90,225		116,029
Noncurrent assets and deferred charges:
Regulatory assets	54,908		55,091
Unamortized debt issuance costs	5,619		5,721
Unrealized gain in fair value of derivative contracts	19,940		23,891
Prepaid pension asset	17,817		19,167
Other	5,747		6,098
	104,031		109,968
Total Assets	$	1,110,491	$	1,122,030
Capitalization and Liabilities
Common stock, $1 par value, 100,000,000 shares authorized, 26,172,406 and 26,084,019 shares issued and outstanding, respectively	$	26,172	$	26,084
Capital in excess of par value	331,206		329,605
Retained earnings	12,941		19,692
Accumulated other comprehensive income, net of income tax	13,721		18,030
Total common stockholders’ equity	384,040		393,411
Long-term debt:
Note payable to securitization trust	50,000		50,000
Obligations under capital lease	606		658
First mortgage bonds and secured debt	109,871		110,015
Unsecured debt	249,127		249,207
Total long-term debt	409,604		409,880
Total long-term debt and common stockholders’ equity	793,644		803,291
Current liabilities:
Accounts payable and accrued liabilities	37,907		59,428
Current maturities of long-term debt	508		503
Obligations under capital lease	148		170
Short-term debt	46,000		30,952
Customer deposits	6,422		6,269
Interest accrued	7,119		3,543
Unrealized loss in fair value of derivative contracts	1,255		2,495
Taxes accrued	4,711		1,831
Other current liabilities	1,186		2,341
	105,256		107,532
Commitments and contingencies (Note 5)
Noncurrent liabilities and deferred credits:
Regulatory liabilities	34,697		32,882
Deferred income taxes	147,010		148,386
Unamortized investment tax credits	4,477		4,501
Postretirement benefits other than pensions	7,586		7,495
Unrealized loss in fair value of derivative contracts	887		907
Minority interest	1,019		1,014
Other	15,915		16,022
	211,591		211,207
Total Capitalization and Liabilities	$	1,110,491	$	1,122,030

See accompanying Notes to Consolidated Financial Statements.

7

THE EMPIRE DISTRICT ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

	Three Months Ended
	March 31,
	2006			2005
	($-000’s)
Operating activities:
Net income (loss)	$	1,612		$	(250	)
Adjustments to reconcile net income (loss) to cash flows from operating activities:
Depreciation and amortization	10,545			9,093
Pension expense	1,376			1,751
Deferred income taxes, net	156			(16		)
Investment tax credit, net	(24		)	4
Allowance for equity funds used during construction	(125		)	(20		)
Stock compensation expense	638			509
Unrealized (gain)/loss on derivatives	(995		)	124
Cash flows impacted by changes in:
Accounts receivable and accrued unbilled revenues	13,547			1,631
Fuel, materials and supplies	(3,417		)	(990		)
Prepaid expenses and deferred charges	(325		)	682
Accounts payable and accrued liabilities	(11,157		)	2,383
Customer deposits, interest and taxes accrued	6,609			7,756
Other liabilities and other deferred credits	8			1,153
Net cash provided by operating activities	18,448			23,810
Investing activities:
Capital expenditures — regulated	(27,425		)	(15,009		)
Capital expenditures and other investments — non-regulated	(658		)	(674		)
Net cash used in investing activities	(28,083		)	(15,683		)
Financing activities:
Proceeds from issuance of common stock	1,052			1,514
Net proceeds/(repayments) from short-term borrowings	4,685			(8,865		)
Dividends	(8,364		)	(8,237		)
Redemption of first mortgage bonds	—			(5		)
Repayments from non-regulated notes payable	(171		)	(97		)
Other	(133		)	(51		)
Net cash used in financing activities	(2,931		)	(15,741		)
Net decrease in cash and cash equivalents	(12,566		)	(7,614		)
Cash and cash equivalents at beginning of period	15,974			12,593
Cash and cash equivalents at end of period	$	3,408		$	4,979

See accompanying Notes to Consolidated Financial Statements.

8

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

Note 1 — Summary of Significant Accounting Policies

The accompanying interim financial statements do not include all disclosures included in the annual financial statements and therefore should be read in conjunction with the financial statements and notes thereto included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2005.

The information furnished reflects all adjustments, consisting only of normal recurring adjustments, which are in our opinion necessary to state fairly the results for the interim periods as well as present these periods on a consistent basis with the financial statements for the fiscal year ended December 31, 2005.

Note 2 — Recently Issued Accounting Standards

In December 2004, the FASB issued Statement of Financial Accounting Standards No. 123 (revised 2004) “Share-Based Payment” (FAS 123R). The statement requires companies to record stock compensation expense in their financial statements based on a fair value methodology beginning no later than the first annual period beginning after June 15, 2005. During 2002, we adopted FAS 148, “Accounting for Stock-Based Compensation — Transition and Disclosure — an Amendment of SFAS 123” (FAS 148) and elected to adopt the accounting provisions of FAS 123 “Accounting for Stock-Based Compensation” (FAS 123). Under FAS 123, we recognized compensation expense over the vesting period of all stock-based compensation awards issued subsequent to January 1, 2002 based upon the fair-value of the award as of the date of issuance. We adopted FAS 123R on January 1, 2006 using the modified prospective application approach. See Note 7 — “Stock-Based Awards and Programs.”

On March 31, 2006, the FASB issued an exposure draft of a proposed Statement of Financial Accounting Standards, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans — an amendment of FASB Statements No. 87, 88 106, and 132(R).” The proposed statement would require a company to recognize on its balance sheet the plan’s overfunded or underfunded status for all plans by recording a net pension and/or other postretirement benefit asset or liability.

The proposed requirement to recognize the over- or underfunded position of pension and other postretirement benefits would be effective for fiscal years ending after December 15, 2006. With the exception of the measurement date amendments, the new requirements would be applied retrospectively to all prior periods presented. Adoption of the proposed standard would result in the recognition of the full amount of our underfunded status related to pension and other postretirement benefit plans as a liability with an off-setting entry to other comprehensive income as of December 31, 2006.

See Note 1 under “Notes to Consolidated Financial Statements” in our Annual Report on Form 10-K for the year ended December 31, 2005 for further information regarding recently issued accounting standards.

Note 3 — Risk Management and Derivative Financial Instruments

We utilize derivatives to help manage our natural gas commodity market risk resulting from purchasing natural gas, to be used as fuel, on the volatile spot market and to manage certain interest rate exposure.

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As of March 31, 2006 and December 31, 2005, we have recorded the following assets and liabilities representing the fair value of qualifying derivative financial instruments held as of that date and subject to the requirements of FAS 133:

Derivative Summary

(In thousands)	March 31, 2006			December 31, 2005
Current assets	$	4,369		$	8,639
Noncurrent assets	19,940			23,891
Current liabilities	(1,255		)	(2,495		)
Noncurrent liabilities	(887		)	(907		)
Fair market value of derivatives (before tax)	22,167			29,128
Tax effect	(8,446		)	(11,098		)
Total OCI — per Balance Sheet	$	13,721		$	18,030
(Unrealized Gain — net of tax)

A $13.7 million net of tax, unrealized gain representing the fair market value of these derivative contracts is recognized as Accumulated Other Comprehensive Income in the capitalization section of the balance sheet as of March 31, 2006. The tax effect of $8.4 million on this gain is included in deferred taxes. These amounts will be adjusted cumulatively on a monthly basis during the determination periods, beginning April 1, 2006 and ending on September 30, 2011. At the end of each determination period, any gain or loss for that period related to the instrument will be reclassified to fuel expense. The decrease in the fair market value of open contracts between December 31, 2005 and March 31, 2006 is due to declining gas futures prices in January and February of 2006 after a large price increase in gas futures prices in the fourth quarter of 2005, due in part to the very active 2005 hurricane season.

We record unrealized gains/(losses) on the overhedged portion of our gas hedging activities in “Fuel” under the Operating Revenue Deductions section of our income statements since all of our gas hedging activities are related to stabilizing fuel costs as part of our fuel procurement program and are not speculative activities.

The following table sets forth “mark-to-market” pre-tax gains/(losses) from the overhedged portion of our hedging activities and the actual pre-tax gains/(losses) from the qualified portion of our hedging activities for settled contracts included in “Fuel” for each of the periods ended March 31:

	Three months ended					Twelve months ended
(In thousands)	2006			2005		2006			2005
Overhedged Portion	$	(34	)	$	193	$	(1,236	)	$	774
Qualified Portion	$	937		$	13	$	5,274		$	8,547

The table above does not include a $1.4 million realized loss from an interest rate derivative contract in June 2005. The benefit and cost of these transactions are recorded as interest expense as amortized.

We also enter into fixed-price forward physical contracts for the purchase of natural gas, coal and purchased power. These contracts are not subject to the fair value accounting of FAS 133 because they are considered to be normal purchases. We have instituted a process to determine if any

10

future executed contracts that otherwise qualify for the normal purchases exception contain a price adjustment feature and will account for these contracts accordingly.

As of April 28, 2006, 85% of our anticipated volume of natural gas usage for the remainder of year 2006 is hedged at an average price of $5.717 per Dekatherm (Dth). In addition, the following volumes and percentages of our anticipated volume of natural gas usage for the next seven years are hedged at the following average prices per Dth:

Year	% Hedged		Dth Hedged	Average Price
2007	60	%	5,860,000	$	6.056
2008	40	%	4,300,000	$	6.585
2009	33	%	3,696,000	$	5.422
2010	42	%	3,696,000	$	5.422
2011	42	%	3,696,000	$	5.422
2012-2013	14	%	2,400,000	$	7.295

Note 4 — Short-Term Borrowings

On July 15, 2005, we entered into a $150 million unsecured revolving credit facility until July 15, 2010. Borrowings (other than through commercial paper) are at the bank’s prime commercial rate or LIBOR plus 80 basis points based on our current credit ratings and the pricing schedule in the line of credit facility. On March 14, 2006, we entered into the First Amended and Restated Unsecured Credit Agreement which amends and restates the $150 million unsecured revolving credit facility. The principal amount of the credit facility was increased to $226 million, with the additional $76 million allocated to support a letter of credit issued in connection with our participation in the Plum Point Power Plant project. This extra $76 million of availability will reduce over the next four years in line with the amount of construction expenditures we owe for Plum Point. The credit facility is used for working capital, general corporate purposes and to back-up our use of commercial paper. This facility requires our total indebtedness (which does not include our note payable to the securitization trust) 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) to be at least two times our interest charges (which includes interest on the note payable to the securitization trust) for 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 the credit facility and will prohibit us from borrowing funds thereunder. As of March 31, 2006, we are in compliance with these ratios. This credit facility is also subject to cross-default if we default on in excess of $10 million in the aggregate on our other indebtedness. This arrangement does not serve to legally restrict the use of our cash in the normal course of operations. There was $46.0 million in outstanding borrowings under this agreement at March 31, 2006. There was no outstanding commercial paper at March 31, 2006.

Note 5 — Commitments and Contingencies

On March 14, 2006, we entered into contracts to add another 100 megawatts of power to our system. This power will come from the Plum Point Power Plant, a new 665-megawatt, coal-fired generating facility which will be built near Osceola, Arkansas beginning in the spring of 2006 with completion scheduled for 2010. Initially we will own 50 megawatts of the project’s capacity for approximately $85 million in direct costs excluding AFUDC. We also have a long term purchased power agreement for an additional 50 megawatts of capacity and have the option to convert the 50 megawatts covered by the purchased power agreement into an ownership interest in 2015.

See also our discussion of pension benefits in Note 6.

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Note 6 — Pension and Other Employment and Post -Employment Benefits

Based on the performance of our pension plan assets through January 1, 2005 and January 1, 2006, we were not required under the Employee Retirement Income Security Act of 1974 (ERISA) to fund any additional minimum ERISA amounts with respect to 2005 or 2006. Our accumulated pension benefit obligation (ABO) was projected to be higher than the fair value of our plan assets at December 31, 2005. Therefore, we elected to make an additional cash contribution of $11.5 million to our pension plan in 2005. This cash contribution had no effect on net income.

We expect to make Other Post-Employment Benefits (OPEB) contributions of $4.9 million in 2006, of which $1.2 million has been made as of March 31, 2006.

The components of our net periodic cost of pension (expensed and capitalized) and other post-employment benefits (in thousands) are summarized below:

	Pension Benefits						OPEB
	Three months ended March 31
	2006			2005			2006			2005
Service cost	$	875		$	875		$	500		$	550
Interest cost	1,750			1,725			825			975
Expected return on plan assets	(2,200		)	(1,925		)	(675		)	(600		)
Amortization of prior service cost	100			125			(100		)	(150		)
Amortization of transition obligation	—			—			—			275
Amortization of net loss	825			925			600			575
Net periodic benefit cost	$	1,350		$	1,725		$	1,150		$	1,625

	Pension Benefits						OPEB
	Twelve months ended March 31
	2006			2005			2006			2005
Service cost	$	3,472		$	2,892		$	2,020		$	1,819
Interest cost	6,710			6,335			3,162			3,131
Expected return on plan assets	(7,976		)	(7,514		)	(2,443		)	(2,042		)
Amortization of prior service cost	469			542			(559		)	(607		)
Amortization of transition obligation	—			—			809			1,088
Amortization of net loss	3,257			1,631			1,945			1,786
Net periodic benefit cost	$	5,932		$	3,886		$	4,934		$	5,175

We began recording a regulatory asset for deferred pension costs during the second quarter of 2005 per our March 10, 2005 Missouri rate case order. As of March 31, 2006, the deferral is approximately $1.8 million, which we expect to collect in rates in future periods. Effective January 1, 2006, we also began recognizing the difference between actual pension costs and pension costs allowed in our Kansas rates. The difference was not material at March 31, 2006.

Note 7 — Stock-Based Awards and Programs

We have several stock-based awards and programs, which are described below. Effective January 1, 2006, we adopted FAS 123(R) “Share-Based Payments” and applied it to our stock-based awards and programs using the modified prospective approach. We had previously recognized compensation expense over the vesting period of all stock-based compensation awards issued subsequent to January 1, 2002 based upon the fair value of the award as of the date of issuance. The adoption of FAS123(R) did not have a material impact on our financial results, as compared to prior periods.

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We recognized the following amounts (in thousands) in compensation expense and tax benefits for all of our stock-based awards and programs, as well as tax windfalls, for the applicable periods ended March 31:

	First Quarter					Twelve Months Ended
	2006		2005			2006		2005
Compensation Expense	$	572	$	469		$	1,687	$	2,039
Tax Benefit Recognized	209		168			606		734
Tax Windfall (Deficit) on Shares Issued	58		(26		)	58		(26		)

The total compensation cost capitalized as part of construction work in progress and plant and property was less than $0.1 million for the twelve months ended March 31, 2006.

Stock Incentive Plans

Our 2006 Stock Incentive Plan (the 2006 Incentive Plan) was adopted by shareholders at the annual meeting on April 28, 2005 and provides for grants of up to 650,000 shares of common stock through January 2016. The 2006 Stock Incentive Plan permits grants of stock options and restricted stock to qualified employees and permits Directors to receive common stock in lieu of cash compensation for service as a Director. The terms of the 2006 Incentive Plan are substantially the same as the 1996 Stock Incentive Plan. Awards made prior to 2006 were made under the 1996 Stock Incentive Plan; awards made on or after January 1, 2006 are made under the 2006 Incentive Plan.

Stock Incentive Plans —Performance-Based Restricted Stock Awards

Beginning in 2002, performance-based restricted stock awards were granted to qualified individuals consisting of the right to receive a number of shares of common stock at the end of the restricted period assuming performance criteria are met. The performance measure for the award is the total return to our shareholders over a three-year period compared with an investor-owned utility peer group. The threshold level of performance under the 2005 and 2006 grants was set at the 20th percentile level of the peer group, target at the 50th percentile level, and maximum at the 80th percentile level. Shares would be earned at the end of the three year performance period as follows: 100% of the target number of shares if the target level of performance is reached, 50% if the threshold is reached, and 200% if the percentile ranking is at or above the maximum, with the number of shares interpolated between these levels. However, no shares would be payable if the threshold is not reached.

The fair value of these stock awards is determined based on the number of shares granted and the quoted price of our stock. Upon adoption of FAS123(R) the fair value of the estimated shares to be awarded under each grant was estimated on the date of grant using a lattice-based option valuation model with the assumptions noted in the following table:

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	2006
Risk-free interest rate	4.54% to 4.60%
Expected volatility of Empire stock	15.2%
Expected volatility of peer group stock	19.8%
Expected dividend yield on Empire stock	5.80%
Expected Forfeiture Rates
Death	0.3%
Disability	0.8%
Retirement	1.7%
Resignation	0.9%
Involuntary Terminations	0.0%
Plan Cycle	3 years
EDE percentile performance	33rd
Fair value percentage (Conversion ratio of target)	51.26%

The 51.26% represents the estimate of the non-vested awards to be granted.

The table below summarizes the performance plan grant and award activity since inception

Non-vested restricted stock awards (based on target number) as of March 31, 2006 and changes during the three months ended March 31, 2006 and 2005 were as follows:

	QTR 1 2006				QTR 1 2005
	Number of shares		Weighted Average Grant Date Fair Value		Number of shares		Weighted Average Grant Date Fair Value
Nonvested at January 1,	40,300		$	20.76	47,100		$	20.32
Granted	13,600		$	22.23	12,100		$	22.77
Awarded	(7,954	)	$	18.25	(8,815	)	$	20.95
Not Awarded	(7,146	)			(10,085	)
Nonvested at March 31,	38,800		$	22.25	40,300		$	20.76

At March 31, 2006 there was $ 0.2 million of total unrecognized compensation cost related to estimated outstanding awards. This cost will be recognized over the outstanding years remaining in the vesting period.

Stock Incentive Plans — Stock Options

Stock options are issued with an exercise price equal to the fair market value of the shares on the date of grant, become exercisable after three years and expire ten years after the date granted. Participants’ options that are not vested become forfeited when participants leave Empire except for terminations of employment under certain specified circumstances. Dividend equivalent awards were also issued to the recipients of the stock options under which dividend equivalents will be accumulated for the three-year period until the option becomes exercisable. For the 2002 awards (the first year options and dividend equivalents were awarded), the dividend equivalents converted to restricted shares of our common stock based on the fair market value of the shares on the date converted. These restricted shares would vest on the eighth anniversary of the grant date of the dividend equivalent award or, if earlier, upon exercise of the related option in full. As all the related options were exercised in 2005, the dividend equivalent restricted shares vested and were payable upon the exercise in full of the related option.

Beginning with the 2003 dividend equivalent awards, the dividend equivalents are accumulated for the three-year period and are converted to shares of our common stock based on the fair market value of the shares on the date converted. To be in compliance with Section 409A of the

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Internal Revenue Code added by the American Jobs Creation Act of 2004, the dividend equivalent awards were changed to vest and be payable in fully vested shares of our common stock on the third anniversary of the grant date (conversion date) or at a change in control and not dependent upon the exercise of the related option. This modification did not have a material impact on our financial statements.

A summary of option activity under the plan during the three months ended March 31, 2006 and 2005 is presented below:

	2006			2005
	Options	Weighted Average Exercise Price		Options	Weighted Average Exercise Price
Outstanding at December 31,	142,500	$	20.84	173,100	$	20.45
Granted	41,700	$	22.23	39,100	$	22.77
Exercised	49,200	$	18.25	69,700	$	20.95
Forfeited	—	—		—	—
Outstanding at March 31	135,000	22.21		142,500	20.84
Exercisable at March 31	—			—	—

The aggregate intrinsic value at March 31, 2006 was immaterial as it was less than $0.1 million. The aggregate intrinsic value at March 31, 2005 was $0.3 million. Total intrinsic value of options exercised for the three months ended March 31, 2006 and 2005 was $0.2 million and $0.1 million, respectively. The intrinsic value of the unexercised options is the difference between Empire’s closing stock price on the last day of the quarter and the exercise price multiplied by the number of in the money options had all option holders exercised their option on the last day of the quarter. The intrinsic value of the exercised options is the difference in the exercised price and the market value at date of exercise.

The range of exercise prices for the options outstanding at March 31, 2006 was $21.79 to $22.77. The weighted-average remaining contractual life of outstanding options at March 31, 2006 and 2005 was 8.8 years and 8.8 years, respectively. The outstanding shares as of March 31, 2006 represents the non-vested shares. As of March 31, 2006, there was $0.4 million of total unrecognized compensation expense related to the non-vested options granted under the plan. That cost will be recognized over a period of 1 to 3 years.

The fair value of the options granted, which is amortized to expense over the option vesting period, has been determined on the date of grant using the methods and assumptions outlined in the table below.

	Stock Options Three months ended March  31
	2006			2005
Valuation Methodology	Black-Scholes			Expanded Black-Scholes
Weighted average fair value of grants	$	1.65		$	4.38
Risk-free interest rate	3.27		%	3.63		%
Dividend yield (1)	6.16		%	0		%
Expected volatility	18.14		%	15.51		%
Expected life in months	60			60
Grant Date	2/1/06			2/3/05

(1)The 2005 grants were valued using an Expanded Black-Scholes method, which included a valuation component for the existence of dividend equivalents, rather than a separate assumption for the dividend equivalents issued under Black-Scholes. In 2006, dividend equivalents were separated from the evaluation.

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Employee Stock Purchase Plan

Our Employee Stock Purchase Plan (ESPP) permits the grant to eligible employees of options to purchase common stock at 90% of the lower of market value at date of grant or at date of exercise. The lookback feature of this plan is valued at 90% of the Black-Scholes methodology plus 10% of the maximum subscription price. As of March 31, 2006, there were 557,820 shares available for issuance in this plan. The adoption of FAS 123(R) did not change the valuation of the options granted under this plan.

	2006		2005
Subscriptions outstanding at March 31	42,532		43,390
Maximum subscription price	$	21.03	$	18.00
Shares of stock issued	—		43,133
Stock issuance price	(1)		$	18.00

(1)           Stock will be issued on the closing date of the purchase period, which runs from June 1, 2005 to May 31, 2006.

Assumptions for valuation of these shares are shown in the table below.

	ESPP Three months ended March 31
	2006			2005
Valuation Methodology	Black-Scholes			Black-Scholes
Weighted average fair value of grants	$	3.24		$	2.68
Risk-free interest rate	3.25		%	1.89		%
Dividend yield	5.5		%	6.4		%
Expected volatility	15.38		%	6.83		%
Expected life in months	12			12
Grant Date	6/1/05			6/1/04

Note 8 — Regulatory Matters

All of our regulatory assets as of March 31, 2006 have been allowed recovery in the state of Missouri as a result of the March 10, 2005 rate case order, except for $4.7 million which primarily consists of $1.4 million in unamortized premiums and related costs for debt reacquired, $1.3 million of loss remaining from a 2005 interest rate derivative transaction and $1.8 million related to deferred Missouri pension costs. These costs were incurred subsequent to our 2004 Missouri rate case filings. Since cost recovery of debt related costs has historically been allowed in rate cases in all of our jurisdictions and the recovery of pension costs was allowed in our last rate case, we expect them to be approved in future rate case proceedings. In addition, losses and gains on our prior interest rate derivatives were included in our recently approved Missouri rate case. Since these items increase and reduce, respectively, our effective interest cost, we believe it is probable they will also be allowed in our other jurisdictions, as well. At March 31, 2006, our regulatory assets totaled $54.9 million.

We are currently collecting an Interim Energy Charge (IEC) of $0.002131 per kilowatt hour of customer usage authorized by the Missouri Public Service Commission (MPSC). This IEC is designed to recover variable fuel and purchased power costs we incur subject to a ceiling and floor on the amount recoverable (including realized gains or losses associated with our natural gas hedging

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program discussed in Note 3) which are higher than such costs included in the base rates allowed in the most recent Missouri rate case. This revenue is recorded when service is provided to the customer and subject to refund to the extent collected amounts exceed variable fuel and purchased power costs. At each balance sheet date, we evaluate the probability that we would be required to refund either a portion or all of the amounts collected under the IEC to ratepayers. At March 31, 2006 and December 31, 2005, no provision for refund had been recorded.

Note 9 — Accounts Receivable — Other

The following table sets forth the major components comprising “Accounts receivable — other” on our consolidated balance sheet (in thousands):

	March 31, 2006		December 31, 2005
Accounts receivable for meter loops, meter bases, line extensions, highway projects, etc.	$	2,079	$	3,570
Accounts receivable for non-regulated subsidiary companies	2,520		3,113
Accounts receivable from Westar Generating, Inc. for commonly-owned facility	1,163		690
Taxes receivable — overpayment of estimated income taxes	2,623		8,504
Accounts receivable for energy trading margin deposit (1)	2,705		2,104
Accounts receivable for true-up on maintenance contracts (2)	1,885		1,193
Other	5		123
Total accounts receivable — other	$	12,980	$	19,297

(1) The $2.7 million accounts receivable for energy trading margin deposit represents the balance in our brokerage account as of March 31, 2006. NYMEX futures contracts are used in our hedging program of natural gas which require posting of margin.

(2) The $1.9 million in accounts receivable for true-up on maintenance contracts represents quarterly estimated credits from Siemens Westinghouse related to our maintenance contract entered into in July 2001 for the State Line Combined Cycle Unit (SLCC). Forty percent of this credit belongs to Westar Generating, Inc., the owner of 40% of the SLCC, and has been recorded in accounts payable as of March 31, 2006.

Note 10 — Regulated — Other Operating Expense

The following table sets forth the major components comprising “Regulated — other” under “Operating Revenue Deductions” on our consolidated statements of operations (in thousands) for all periods presented ended March 31:

	Three Months Ended		Three Months Ended		Twelve Months Ended		Twelve Months Ended
	2006		2005		2006		2005
Transmission and distribution expense	$	1,960	$	1,753	$	8,331	$	7,181
Power operation expense (other than fuel)	2,164		2,181		9,536		9,517
Customer accounts and assistance expense	1,756		1,686		7,037		7,041
Employee pension expense (1)	846		1,472		2,935		3,788
Employee healthcare plan	1,857		2,528		8,015		8,761
General office supplies and expense	1,757		1,584		6,964		7,534
Administrative and general expense	2,270		2,323		8,511		8,139
Allowance for uncollectible accounts	237		571		1,480		1,355
Miscellaneous expense	22		37		92		117
Total	$	12,869	$	14,135	$	52,901	$	53,433

(1) Does not include capitalized portion or amount deferred to a regulatory asset.

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Note 11 — Segment Information

The Company’s business is composed of two segments, regulated and other. The regulated segment consists of the Company’s electric and water utility businesses. The other segment consists of all our other businesses. These businesses are unregulated and include a 100% interest in Empire District Industries, Inc., a subsidiary for our fiber optics business; a 100% interest in Conversant, Inc., a software company that markets Customer Watch, an Internet-based customer information system software, a 100% interest in Utility Intelligence, Inc., a company that distributes automated meter reading equipment; a 100% interest in Fast Freedom, Inc., an Internet provider; and a controlling 52% interest in MAPP, a company that specializes in close-tolerance custom manufacturing for the aerospace, electronics, telecommunications and machinery industries, including components for specialized batteries for Eagle Picher Technologies.

Labor costs from regulated employees who perform duties for the other segment are charged to non-regulated labor expense.

The table below presents information about the reported revenues, operating income, net income, capital expenditures, total assets and minority interests of our business segments.

	For the quarters ended March 31, 2006
	Regulated		Other			Eliminations			Total
	($-000’s)
Statement of Operations Information
Revenues	$	83,087	$	5,009		$	(167	)	$	87,929
Operating income (loss)	9,232		(383		)	—			8,849
Net income (loss)	2,049		(437		)	—			1,612
Minority interest	—		30			—			30
Capital Expenditures	27,425		658			—			28,083

	2005
Statement of Operations
Revenues	$	73,623	$	6,057		$	(145	)	$	79,535
Operating income (loss)	7,507		(341		)	—			7,166
Net income (loss)	181		(431		)	—			(250		)
Minority interest	—		(27		)	—			(27		)
Capital Expenditures	15,009		674			—			15,683

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	As of March 31, 2006
	Regulated		Other			Eliminations(1)			Total
	($-000’s)
Balance Sheet Information
Total assets	$	1,108,942	$	26,088		$	(24,539	)	$	1,110,491
Minority interest	—		(1,019		)	—			(1,019		)

	As of December  31, 2005
Balance Sheet Information
Total assets	$	1,119,773	$	26,396		$	(24,139	)	$	1,122,030
Minority interest	—		(1,014		)	—			(1,014		)

(1)Reflects the elimination of the “Investment in subsidiaries” recorded in the accounts of the regulated segment.

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

EXECUTIVE SUMMARY

TheEmpire District Electric Company is an operating public utility engaged in the generation, purchase, transmission, distribution and sale of electricity in parts of Missouri, Kansas, Oklahoma and Arkansas. We also provide water service to three towns in Missouri. The utility operations comprise our regulated segment. We also have an other segment which includes investments in certain non-regulated businesses including fiber optics, Internet access, close-tolerance custom manufacturing and customer information system software services. These businesses are held in our wholly-owned subsidiary, EDE Holdings, Inc. In 2005, 92.9% of our gross operating revenues were provided from the sale of electricity, 0.4% from the sale of water, both of which are included in our regulated segment, and 6.7% from our non-regulated businesses. There were no significant changes in these percentages for the first quarter of 2006.

The primary drivers of our electric operating revenues in any period are: (1) rates we can charge our customers, (2) weather, (3) customer growth and (4) general economic conditions. The utility commissions in the states in which we operate, as well as the Federal Energy Regulatory Commission (FERC), set the rates at which we can charge our customers. In order to offset expenses, we depend on our ability to receive adequate and timely recovery of our costs (primarily fuel and purchased power) and/or rate relief. We continue to assess the need for rate relief in all of the jurisdictions we serve and file for such relief when necessary. Weather affects the demand for electricity for our regulated business. Very hot summers and very cold winters increase demand, while mild weather reduces demand. Residential and commercial sales are impacted more by weather than industrial sales, which are mostly affected by business needs for electricity and general economic conditions. Customer growth, which is the growth in the number of customers, contributes to the demand for electricity. We expect our annual customer growth to range from approximately 1.6% to 1.8% over the next several years, although our customer growth for the twelve months ended March 31, 2006 was 2.2%. We define sales growth to be growth in kWh sales excluding the impact of weather. The primary drivers of sales growth are customer growth and general economic conditions.

The primary drivers of our electric operating expenses in any period are: (1) fuel and purchased power expense, (2) maintenance and repairs expense, (3) employee pension and health care costs, (4) taxes and (5) non-cash items such as depreciation and amortization expense. Fuel and purchased power costs are our largest expense items. Several factors affect these costs, including fuel and purchased power prices, plant outages and weather, which drives customer demand. In order to control the price we pay for fuel and purchased power, we have entered into long and short-term agreements to purchase power (including wind energy) and coal and natural gas for our energy supply. We currently engage in hedging activities in an effort to minimize our risk from volatile natural gas prices. We enter into contracts with counterparties relating to our future natural gas requirements that lock in

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prices (with respect to predetermined percentages of our expected future natural gas needs) in an attempt to lessen the volatility in our fuel expense and improve predictability.Our 2005 Missouri rate case order also contained factors to help mitigate the above costs, including an Interim Energy Charge (IEC), designed to recover variable fuel and purchased power costs we incur which are higher than such costs included in the base rates allowed in our rate case. However, due to the extremely high fuel prices, IEC revenues recorded in the second, third and fourth quarters of 2005 and the first quarter of 2006 did not recover all the Missouri related fuel and purchased power costs incurred in those quarters. As a result, on February 1, 2006, we filed a request with the MPSC for an annual increase in base rates for our Missouri electric customers in the amount of $29.5 million, or 9.63%, and requested transition from the IEC to Missouri’s new fuel adjustment mechanism. However, the MPSC issued an order May 2, 2006 ruling that we may have the option of requesting that the IEC be terminated, but we may not request the implementation of an energy cost recovery mechanism while the current IEC is effective. Our recent Kansas rate case order contained a change in the recognition of pension costs, allowing us to defer the Kansas portion of any costs above the amount included in our rate case as a regulatory asset. In addition, the Arkansas Public Service Commission (APSC) allowed us to adjust our annual Energy Cost Recovery (ECR) rate midway through the regulatory year due to higher gas prices with the adjusted interim rate effective October 1, 2005 through March 31, 2006.

We entered into a letter of intent with KCP&L on June 10, 2005 with respect to our potential purchase of an undivided ownership interest in the proposed 800-850 MW coal-fired Iatan 2. The total estimated construction budget for Iatan 2 is approximately $1.26 billion with the first major expenditures for our share, approximately $28.7 million and $51.9 million, planned in 2007 and 2008, respectively. KCP&L has notified us of an acceleration of costs from previous estimates. The acceleration would increase our 2006, 2007 and 2008 budgeted expenditures by approximately $8 million, $17 million and $11 million, respectively, with a corresponding decrease expected in 2009 and 2010. KCP&L has informed us their definitive estimates for Iatan 2 should be finalized by mid-summer and there is the potential for an increase in overall cost. The letter of intent relates to an allocation of at least 100 MW of generation capacity (and a proportionate share of the construction, operation and maintenance costs) to us. The letter of intent, insofar as it relates to Iatan 2, is not binding on the parties. The letter of intent also contains a clarification as to our obligations with respect to environmental upgrades at Iatan 1 and an agreement to reallocate certain interests in common facilities at Iatan 1 to the owners of Iatan 2. Empire currently owns a 12% interest in Iatan 1.

On March 14, 2006, we entered into contracts to add another 100 megawatts of power to our system. This power will come from the Plum Point Power Plant, a new 665-megawatt, coal-fired generating facility which will be built near Osceola, Arkansas beginning in the spring of 2006 with completion scheduled for 2010. Initially we will own 50 megawatts of the project’s capacity. We also have a long term purchased power agreement for an additional 50 megawatts of capacity and have the option to convert the 50 megawatts covered by the purchased power agreement into an ownership interest in 2015.

Plum Point and Iatan 2, are important components of a long-term, least-cost resource plan to add approximately 300 megawatts of coal-fired generation to our system by mid-2010. The plan is driven by the continued growth in our service area, the expiration of a major purchased power contract in 2010 and our desire to reduce our dependence on natural gas-fired generation.

During the first quarter of 2006, basic and diluted earnings (loss) per weighted average share of common stock increased to $0.06 as compared to $(0.01) in the first quarter of 2005 despite milder weather in the first quarter of 2006 as compared to the same period in 2005. For the twelve months ended March 31, 2006, basic and diluted earnings per weighted average share of common stock were $0.99 as compared to $0.78 for the twelve months ended March 31, 2005. As reflected in the table below, the primary positive driver for the increased earnings in both periods was increased revenues, while the primary negative driver was increased fuel and purchased power costs.

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The following reconciliation of basic earnings per share between the first quarter of 2005 and the first quarter of 2006 and between the twelve months ended March 31, 2005 and March 31, 2006 is a non-GAAP presentation. We believe this information is useful in understanding the fluctuation in earnings per share between the prior and current year periods. The reconciliation presents the after tax impact of significant items and components of the statement of operations on a per share basis before the impact of additional stock issuances which is presented separately. Earnings per share for the quarters and twelve months ended March 31, 2006 and 2005 shown in the reconciliation are presented on a GAAP basis and are the same as the amounts included in the statements of operations. This reconciliation may not be comparable to other companies or more useful than the GAAP presentation included in the statements of operations.

	First Quarter			Twelve Months Ended
Earnings Per Share — 2005	$	(0.01	)	$	0.78
Revenues
On- System - Electric	$	0.29		$	1.57
Off — System and other - Electric	(0.05		)	0.08
Non — Regulated	(0.03		)	0.07
Expenses
Fuel	0.05			(1.05		)
Purchased power	(0.20		)	(0.25		)
Regulated — other (employee health care and pension expense only)	0.03			0.04
Regulated — other (all other)	0.00			(0.02		)
Non — Regulated	0.03			(0.01		)
Maintenance and repairs	0.00			(0.02		)
Depreciation and amortization	(0.04		)	(0.15		)
Other taxes	(0.01		)	(0.03		)
Interest charges	0.00			0.01
Other income and deductions	0.00			(0.02		)
Dilutive effect of additional shares	0.00			(0.01		)
Earnings Per Share — 2006	$	0.06		$	0.99

First Quarter Activities

On September 21, 2005, we announced that we had entered into an Asset Purchase Agreement with Aquila, Inc., pursuant to which we agreed to acquire the Missouri natural gas distribution operations of Aquila, Inc. (Missouri Gas). The Missouri Gas properties consist of approximately 48,500 customers in 44 Missouri communities in northwest, north central and west central Missouri. The base purchase price, originally $84 million in cash, plus working capital and subject to net plant adjustments, was increased to $85 million in February 2006 due to an amendment to the purchase agreement where Aquila will retain certain liabilities and obligations originally to have been assumed by us. We expect the acquisition to be financed with a mix of debt and equity consistent with our current capital structure. This transaction is subject to the approval of the Missouri Public Service Commission (MPSC) and other customary closing conditions. We received notice of early termination of the Hart-Scott-Rodino Antitrust Improvements Act waiting period in January 2006. We filed an application with the MPSC on November 8, 2005 seeking approval. On March 1, 2006, we, Aquila Inc., the MPSC staff, the Office of the Public Counsel (OPC) and three intervenors filed a unanimous stipulation and agreement with

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the MPSC, requesting they approve the proposed transaction. On April 18, 2006, the MPSC issued an Order Approving Unanimous Stipulation and Agreement and Granting a Certificate of Public Convenience and Necessity, effective May 1, 2006. We expect to close the acquisition on June 1, 2006.

At April 30, 2006, the construction at our Riverton plant was still on schedule for the installation of our new Siemens V84.3A2 combustion turbine, with the turbine and the 155 megawatt generator both delivered and set on the foundation in April 2006. The V84 is scheduled to be operational in 2007.

On April 29, 2005, we filed a request with the Kansas Corporation Commission (KCC) for an increase in base rates for our Kansas electric customers in the amount of $4.2 million, or 24.64%. On October 4, 2005, we and the KCC Staff filed a Motion to Approve Joint Stipulated Settlement Agreement (Agreement) with the KCC. The Agreement called for an annual increase in rates for our Kansas electric customers of approximately $2.15 million, or 12.67%, and the implementation of an Energy Cost Adjustment Clause (ECA), a fuel rider that will collect fuel costs in the future. In addition, the Agreement allows us to change our recognition of pension costs, deferring the Kansas portion of any costs above the amount included in this rate case as a regulatory asset. The KCC approved the Agreement on December 9, 2005 with an effective date of January 4, 2006. For additional information, see “- Results of Operations — Regulated Segment — Electric Operating Revenues and Kilowatt-Hour Sales — Rate Matters” below.

Several of the nation’s utilities, including Empire, are still experiencing decreased coal inventory levels due to railroad transportation problems delivering Western coal. As of March 31, 2006, we had approximately 21 days of Western coal inventory at our Riverton plant and approximately 47-52 days (depending on the actual blend ratio) of Western coal inventory at our Asbury plant, compared to over 70 days and approximately 75 days, respectively, as of June 30, 2005 and approximately 27 days and 27-40 days respectively, as of December 31, 2005. As the railroads continue their rail maintenance in 2006, it is anticipated that congestion problems will continue to affect delivery cycle times and we will continue conservation measures until a change in circumstances occurs. Since July 2005, we have leased a train on an interim basis, which slowed the rate of decline. However, on our train’s last trip to Wyoming, which concluded May 1, 2006, 51 of the train’s 125 cars were damaged during transit and are not serviceable in their current condition. We are currently assessing the cause of the damage and the cost and time to repair the damage. In the meantime, we have secured cars to keep our coal supply going and are evaluating the impact of the damage. Similar issues, such as slow cycle times, have also affected Iatan. Our coal conservation measures at both Asbury and Riverton have included increased use of local coals not dependent upon railroad transportation. We continue coal conservation measures at Iatan which have had a negative impact on our earnings in 2005 and in the first quarter of 2006. Also, power deliveries under our purchase power contract with Westar Energy are still being reduced due to coal conservation efforts by Westar. This also had a negative impact on our earnings in 2005 and in the first quarter of 2006. Currently, both KCP&L and Westar Energy are making provisions to ensure that sufficient coal supplies are available for the summer months. This coal transportation situation and our coal conservation and supply replacement measures could have an adverse effect on our fuel and purchased power costs in future periods.

RESULTS OF OPERATIONS

The following discussion analyzes significant changes in the results of operations for the three-month and twelve-month periods ended March 31, 2006, compared to the same periods ended March 31, 2005.

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Regulated Segment

Electric Operating Revenues and Kilowatt-Hour Sales

Of our total electric operating revenues during the first quarter of 2006 approximately 45% were from residential customers, 27% from commercial customers, 17% from industrial customers, 5% from wholesale on-system customers, 2% from wholesale off-system transactions and 4% from miscellaneous sources, primarily transmission services. The breakdown of our customer classes has not significantly changed from the first quarter of 2005.

The amounts and percentage changes from the prior periods in kilowatt-hour (“kWh”) sales and operating revenues by major customer class for on-system sales were as follows:

	kWh Sales (in millions)				kWh Sales (in millions)
	First	First			12 Months	12 Months
	Quarter	Quarter			Ended	Ended
	2006	2005	% Change*		2006	2005	% Change*
Residential	474.1	494.4	(4.1	)%	1,861.1	1,698.8	9.6	%
Commercial	330.3	324.0	1.9		1,491.3	1,411.0	5.7
Industrial	265.8	249.9	6.4		1,122.6	1,081.4	3.8
Wholesale On-System	78.0	75.3	3.6		331.5	307.8	7.7
Other**	26.0	27.1	(3.9	)	111.9	107.4	4.2
Total On-System	1,174.2	1,170.7	0.3		4,918.4	4,606.4	6.8

	Operating Revenues ($ in millions)						Operating Revenues ($ in millions)
	First		First				12 Months		12 Months
	Quarter		Quarter				Ended		Ended
	2006***		2005		% Change*		2006***		2005		% Change*
Residential	$	36.9	$	32.6	13.1	%	$	153.5	$	124.8	23.0	%
Commercial	22.7		19.4		16.8		109.3		92.4		18.3
Industrial	14.0		11.2		25.0		62.4		51.9		20.3
Wholesale On-System	4.3		3.4		25.9		17.5		13.8		26.3
Other**	1.9		1.8		8.3		8.7		7.6		15.1
Total On-System	$	79.8	$	68.4	16.6		$	351.4	$	290.5	21.0

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

**Other kWh sales and other operating revenues include street lighting, other public authorities and interdepartmental usage.

***Revenues include approximately $2.0 million of the Interim Energy Charge collected in the first quarter of 2006 and approximately $8.6 million collected in the twelve months ended March 31, 2006 that are not expected to be refunded to customers. See discussion below.

On-System Electric Transactions

KWh sales for our on-system customers increased slightly during the first quarter of 2006 as compared to the first quarter of 2005 primarily due to continued sales growth, but were negatively impacted by milder weather. Revenues for our on-system customers increased approximately $11.4 million, or 16.6%. The March 2005 Missouri rate increase, May 2005 Arkansas rate increase and January 2006 Kansas rate increase (discussed below) contributed an estimated $9.6 million to revenues while continued sales growth contributed an estimated $1.8 million during the first quarter of 2006 with weather and other factors having a negative impact on revenues of an estimated $2.0 million. The collected IEC which is not expected to be refunded contributed approximately $2.0

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million during the first quarter of 2006. We expect our annual customer growth to range from approximately 1.6% to 1.8% over the next several years, although our customer growth for the twelve months ended March 31, 2006 was 2.2%.

The decrease in residential kWh sales during the first quarter of 2006 was primarily due to milder weather conditions. Total heating degree days (the sum of the number of degrees that the daily average temperature for that period was below 65° F) for the first quarter of 2006 were 9.6% less than the same period last year and 19.3% less than the 30-year average. Despite the decreased kWh sales, revenues for our on-system customers increased approximately $11.4 million. Revenues were positively affected by the March 2005 Missouri rate increase, May 2005 Arkansas rate increase and January 2006 Kansas rate increase and related fuel adjustment increases.

Commercial kWh sales and industrial kWh sales increased for the first quarter of 2006 mainly due to continued sales growth while associated revenues increased reflecting the Missouri, Arkansas and Kansas rate increases.

On-system wholesale kWh sales increased during the first quarter of 2006 reflecting the continued sales growth discussed above. Revenues associated with these FERC-regulated sales increased more as a result of the fuel adjustment clause applicable to such sales. This clause permits the distribution to customers of changes in fuel and purchased power costs.

For the twelve months ended March 31, 2006, kWh sales to our on-system customers increased 6.8% with the associated revenues increasing approximately $60.9 million (21.0%). The 2005 Missouri and Arkansas rate increases and the 2006 Kansas rate increase contributed an estimated $34.3 million to revenues while continued sales growth contributed an estimated $6.1 million. Weather and other related factors contributed an estimated $11.9 million. The collected IEC which is not expected to be refunded contributed approximately $8.6 million during the twelve months ended March 31, 2006. Residential and commercial kWh sales and associated revenues increased primarily due to warmer temperatures in the second and third quarters of 2005 and colder temperatures in the fourth quarter of 2005 as compared to the prior year periods, continued sales growth and the Missouri, Arkansas and Kansas rate increases. Industrial sales and associated revenues increased during the twelve months ended March 31, 2006 primarily due to continued sales growth and the aforementioned rate increases. On-system wholesale kWh sales and revenues increased for the twelve months ended March 31, 2006 reflecting continued sales growth and the operation of the fuel adjustment clause applicable to these FERC regulated sales.

Rate Matters

The following table sets forth information regarding electric and water rate increases since January 1, 2005:

		Annual	Percent
	Date	Increase	Increase	Date
Jurisdiction	Requested	Granted	Granted	Effective
Missouri - Water	June 24, 2005	$     469,000	35.90%	February 4, 2006
Kansas - Electric	April 29, 2005	2,150,000	12.67%	January 4, 2006
Arkansas - Electric	July 14, 2004	595,000	7.66%	May 14, 2005
Missouri - Electric	April 30, 2004	25,705,500	9.96%	March 27, 2005

On April 30, 2004, we filed a request with the MPSC for an annual increase in base rates for our Missouri electric customers in the amount of $38,282,294, or 14.82%. On December 22, 2004, we, the MPSC Staff, the OPC and two intervenors filed a unanimous Stipulation and Agreement as to Certain Issues with the MPSC settling several issues. One of the issues we were able to agree on was a change in the recognition of pension costs allowing us to defer the Missouri portion of any

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costs above the amount included in this rate case as a regulatory asset. The amount of pension cost allowed in this rate case was approximately $3.0 million. This stipulation became effective on March 27, 2005 as part of the final Missouri order described below. Therefore, the deferral of these costs began in the second quarter of 2005.

The MPSC issued a final order on March 10, 2005 approving an annual increase in base rates of approximately $25,705,500, or 9.96%, effective March 27, 2005. The order granted us a return on equity of 11%, an increase in base rates for fuel and purchased power at $24.68/MWH and an increase in depreciation rates. The new depreciation rates now include a cost of removal component of mass property (transmission, distribution and general plant costs). In addition, the order approved an annual IEC of approximately $8.2 million effective March 27, 2005 and expiring three years later. The IEC is $0.002131 per kilowatt hour of customer usage. The MPSC allowed us to use forecasted fuel costs rather than the traditional historical costs in determining the fuel portion of the rate increase. At the end of two years, an assessment will be made of the money collected from customers compared to the greater of the actual and prudently incurred costs or the base cost of fuel and purchased power set in rates. If the excess of the amount collected over the greater of these two amounts is greater than $10 million, the excess over $10 million will be refunded to the customers. The entire excess amount of IEC, not previously refunded, will be refunded at the end of three years, unless the IEC is terminated earlier. Each refund will include interest at the current prime rate at the time of the refund. The IEC revenues recorded in the second, third and fourth quarters of 2005 and the first quarter of 2006 did not recover all the Missouri related fuel and purchased power costs incurred in those quarters. From inception of the IEC through March 31, 2006, the costs of fuel and purchased power were approximately $18.4 million higher than the total of the costs in our base rates and the IEC recorded during the period. Future recovery of fuel and purchased power costs through the IEC are dependent upon a variety of factors, including natural gas prices, costs of non-contract purchased power, weather conditions, plant availability and coal deliveries. At March 31, 2006, no provision for refund has been recorded.

On March 25, 2005, we, the OPC, the Missouri Industrial Energy Consumers and intervenors Praxair, Inc. and Explorer Pipeline Company, filed applications with the MPSC requesting the MPSC grant a rehearing with respect to the return on equity granted in the March 2005 Missouri rate case. The MPSC denied these applications on April 7, 2005. We and the OPC appealed this decision to the Cole County Circuit Court, which denied all appeals and affirmed the MPSC’s March 2005 Report and Order on March 13, 2006. Any opportunity for further appeal expired April 24, 2006.

On July 14, 2004, we filed a request with the APSC for an annual increase in base rates for our Arkansas electric customers in the amount of $1,428,225, or 22.1%. On May 13, 2005, the APSC granted an annual increase in electric rates for our Arkansas customers of approximately $595,000, or 7.66%, effective May 14, 2005. In September 2005, the APSC allowed us to adjust our annual ECR rate midway through the regulatory year due to higher gas prices with the adjusted interim rate effective October 1, 2005 through March 31, 2006.

On April 29, 2005, we filed a request with the Kansas Corporation Commission (KCC) for an increase in base rates for our Kansas electric customers in the amount of $4,181,078, or 24.64%. On October 4, 2005, we and the KCC Staff filed a Motion to Approve Joint Stipulated Settlement Agreement (Agreement) with the KCC. The Agreement called for an annual increase in base rates (which includes historical fuel costs) for our Kansas electric customers of approximately $2,150,000, or 12.67%, the implementation of an Energy Cost Adjustment Clause (ECA), a fuel rider that will collect or refund fuel costs in the future that are above or below the fuel costs included in the base rates and the adoption of the same depreciation rates approved by the MPSC in our last Missouri rate case. In addition, we will be allowed to change our recognition of pension costs, deferring the Kansas portion of any costs above the amount included in this rate case as a regulatory asset. The KCC approved the Agreement on December 9, 2005 with an effective date of January 4, 2006.

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Pursuant to the Agreement, we were to seek KCC approval of an explicit hedging program in a separate docket by March 1, 2006. However, we requested and received an extension until April 1, 2006. We made this filing on March 30, 2006 and are awaiting a response from the KCC.

On June 24, 2005, we filed a request with the MPSC for an annual increase in base rates for our Missouri water customers in the amount of $523,000, or 38%. The MPSC issued a final order on January 31, 2006 approving an annual increase in base rates of approximately $469,000, or 35.9%, effective February 4, 2006.

On February 1, 2006, we filed a request with the MPSC for an annual increase in base rates for our Missouri electric customers in the amount of $29,513,713, or 9.63%. We expect the unprecedented high natural gas prices to continue to negatively impact our fuel and purchased power expenses in the near future. In addition, the coal delivery problems discussed above, as well as decreased output from our Ozark Beach hydro plant due to dry weather conditions, have also had a negative impact on our fuel costs. Given our limited ability to recover these added costs, we also requested transition from the IEC to Missouri’s new fuel adjustment mechanism. However, the MPSC issued an order May 2, 2006 ruling that we may have the option of requesting that the IEC be terminated, but we may not request the implementation of an energy cost recovery mechanism while the current IEC is effective. At this time, we cannot predict the outcome of this rate case filing.

We will continue to assess the need for rate relief in all of the jurisdictions we serve and file for such relief when necessary.

Off-System Electric Transactions

In addition to sales to our own customers, we also sell power to other utilities as available and provide transmission service through our system for transactions between other energy suppliers. The following table sets forth information regarding these sales and related expenses for the applicable periods ended March 31:

	2006				2005
	First		Twelve Months		First		Twelve Months
	Quarter		Ended		Quarter		Ended
(in millions)
Revenues	$	2.3	$	14.9	$	4.3	$	11.6
Expenses	1.7		11.0		2.7		7.1
Net*	$	0.7	$	4.0	$	1.6	$	4.5

*Differences could occur due to rounding.

Revenues less expenses were less for both the first quarter of 2006 and the twelve months ended March 31, 2006 as compared to the same periods in 2005. Revenues and related expenses were less during the first quarter of 2006 as compared to 2005 due to decreased market demand resulting from the mild weather in the first quarter of 2006. Revenues were higher during the twelve months ended March 31, 2006 as compared to 2005 primarily due to increased sales of our gas-fired generation in the third and fourth quarters of 2005 due to a shortage of available coal-fired generation on the open market. Companies that normally would have coal-fired energy to sell in the market were not doing so due to the coal shortages, pushing demand onto the gas-fired units. As a result, the related expenses were also higher primarily due to increased fuel costs for the power we sold. These expenses are included in our discussion of purchased power costs below.

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Operating Revenue Deductions

During the first quarter of 2006, total operating expenses increased approximately $6.7 million (9.3%) compared with the same period last year. Fuel costs decreased approximately $1.9 million (8.2%) but were offset by a $7.8 million (64.5%) increase in purchased power costs during the first quarter of 2006. The decrease in fuel costs was primarily due to decreased generation by our gas fired units in the first quarter of 2006 (an estimated $7.4 million) partially offset by higher prices for the hedged natural gas that we burned in our gas-fired units and losses on the sale of excess gas. The effect of these two components was an estimated $5.4 million, including the loss on the sale of gas of $1.6 million. The increase in purchased power costs primarily reflected that it was more economical to purchase power than it was to run our own generating units during the first quarter of 2006 and also reflected the unplanned outage at our Asbury plant due to a blade failure in February. As a result, the Asbury 2006 spring outage was moved to the first quarter with Asbury back on line, however, by March 3, 2006. The net increase in fuel and purchased power during the first quarter of 2006 as compared to the same period last year was $5.9 million (17.0%).

Regulated — other operating expenses decreased approximately $1.3 million (9.0%) during the first quarter of 2006 as compared to the same period in 2005 primarily due to a $1.3 million decrease in expenses relating to our employee health care plan and our employee pension expense. Customer accounts expense decreased $0.3 million during the first quarter of 2006 as compared to the first quarter of 2005 when we recorded a $0.3 million reserve due to the bankruptcy filing of Eagle Picher, one of our industrial customers. This decrease in expense was offset by a $0.3 million increase in transmission expense during the first quarter of 2006. As discussed previously, effective with the second quarter of 2005, we began deferring a portion of our pension cost into a regulatory asset as authorized in our 2005 Missouri rate case. We have deferred approximately $1.8 million as of March 31, 2006.

Non-regulated operating expense for all periods presented is discussed below under “-Other Segment”.

Maintenance and repairs expense increased approximately $0.4 million (8.5%) as compared to the first quarter of 2005 primarily due to a $0.8 million increase in maintenance at the Asbury plant related to the first quarter unscheduled outage discussed above and to a $0.2 million increase in maintenance and repairs expense for our State Line Combined Cycle plant. These increases were partially offset by a $0.7 million decrease in maintenance and repairs expense at our Iatan plant as compared to the first quarter of 2005 when a scheduled outage occurred in March 2005.

Depreciation and amortization expense increased approximately $1.5 million (18.8%) during the quarter due primarily to higher depreciation rates that became effective on March 27, 2005. The provision for income taxes increased approximately $0.9 million during the first quarter of 2006 due to higher taxable income. Our effective federal and state income tax rate for the first quarter of 2006 was 34.0% as compared to 34.4% for the first quarter of 2005. Other taxes increased approximately $0.2 million during the first quarter of 2006.

During the twelve months ended March 31, 2006, total operating expenses increased approximately $61.6 million (22.1%) compared to the year ago period. Total fuel costs increased approximately $40.8 million (58.2%) during the twelve months ended March 31, 2006 and purchased power costs increased $9.6 million (18.9%) during the same period. The increase in fuel costs was primarily due to higher prices for both the hedged and unhedged natural gas that we burned in our gas-fired units (an estimated $25.6 million) and increased generation by our gas-fired units (an estimated $10.6 million). Increased coal costs contributed approximately $2.4 million to the total fuel increase and increased coal generation added approximately $0.3 million. These increased costs reflect a $5 million one-time pre-tax gain from unwinding part of a physical purchase of natural gas for the 2009 through 2011 period as part of our fuel management process. This gain was recognized

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in the third quarter of 2005 as a decrease to fuel expense. Natural gas prices increased in 2005, in part, from the effects of hurricane activity in the Gulf of Mexico. The increased usage was due in part to weather, as well as changes in the wholesale market impacted by coal delivery issues in the Midwest. The net increase in fuel and purchased power during the twelve months ended March 31, 2006 as compared to the same period last year was $50.4 million (41.7%).

Regulated — other operating expenses decreased approximately $0.5 million (1.0%) during the twelve months ended March 31, 2006 as compared to the same period last year due primarily to a $0.9 million decrease in employee pension expense, a decrease of approximately $0.7 million in employee health care expense and a $0.8 million decrease in general administrative expense due to decreased costs associated with Sarbanes-Oxley Section 404 compliance. These decreases in regulated — other operating expense were partially offset by a $1.1 million increase in transmission expense, a $0.5 million increase in professional services expense, a $0.2 million increase in regulatory commission expense and a $0.2 million increase in labor costs.

Maintenance and repairs expense increased approximately $0.9 million (4.3%) during the twelve months ended March 31, 2006, compared to the year ago period reflecting increases of approximately $0.4 million in transmission maintenance costs and $0.3 million in maintenance costs for our coal-fired units, particularly at the Asbury plant.

Depreciation and amortization expense increased approximately $6.0 million (19.2%) due to higher depreciation rates that became effective on March 27, 2005 and increased plant in service. Provision for income taxes increased $2.8 million reflecting increased taxable income during the current period while other taxes increased approximately $1.4 million (7.7%) due to increased property taxes reflecting our additions to plant in service and increased municipal franchise taxes. Our effective federal and state income tax rate for the twelve months ended March 31, 2006 was 33.4% as compared to 34.1% for the same period in 2005.

Other Segment

Our business is composed of two segments, regulated and other. The regulated segment consists of our electric and water utility businesses. Our other business segment is operated through our wholly-owned subsidiary EDE Holdings, Inc. It includes leasing of fiber optics cable and equipment (which we are also using in our own operations), Internet access, close-tolerance custom manufacturing and customer information system software services.

We evaluated our other segment businesses for impairment at December 31, 2005 and believe, based on this analysis, that no impairment exists based on our forecast of future net cash flows. However, failure to achieve forecasted cash flows and execute software license agreements within our software business, could result in impairment in the future. There have been no significant changes in our forecasted future net cash flows since December 31, 2005, thus, we believe that no impairment exists in our other segment businesses as of March 31, 2006.

During the first quarter of 2006, total other segment operating revenue decreased approximately $1.1 million (17.7%) while total other segment operating expense decreased approximately $1.0 million (16.5%) as compared to the first quarter of 2005. The decrease in both operating revenue and expense was mainly attributed to MAPP, the close-tolerance custom manufacturing business in which we own a 52% interest.

Our other segment businesses generated a $0.4 million net loss in both the first quarter of 2006 and the first quarter of 2005, primarily due to Conversant, a software company in which we own a 100% interest. Conversant markets Customer Watch, an Internet-based customer information system software.

For the twelve-months ended March 31, 2006, total other segment operating revenue increased approximately $2.6 million (11.7%) while total other segment operating expense increased

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approximately $0.6 million (2.4%) compared with the same period in 2005. The increase in revenues for the twelve-month-ended period was primarily due to MAPP while the increase in expense was primarily due to MAPP and Conversant.

Our other segment businesses generated a $1.1 million net loss for the twelve-months ended March 31, 2006 as compared to a $1.9 million net loss for the same period in 2005.

Nonoperating Items

Total allowance for funds used during construction (“AFUDC”) increased $0.5 million during the first quarter of 2006 and increased $0.8 million during the twelve months ended March 31, 2006 due to higher levels of construction as compared to the same periods in 2005.

Total interest charges on long-term debt decreased $0.2 million (3.0%) for the first quarter of 2006 as compared to the first quarter of 2005 and decreased $0.8 million (3.1%) during the twelve months ended March 31, 2006 as compared to the same period in 2005 primarily reflecting the refinancing we accomplished in June 2005 by calling a higher interest debt issue and replacing it with a debt issue at a lower interest rate. See “ - Liquidity and Capital Resources” for further information. Short-term debt interest increased $0.4 million during the first quarter of 2006 as compared to 2005 and increased $0.6 million for the twelve months ended March 31, 2006 as compared to the same period in 2005, reflecting increased usage of short-term debt.

Other Comprehensive Income

The change in the fair value of the effective portion of our open gas contracts and our interest rate derivative contracts and the gains and losses on contracts settled during the periods being reported, including the tax effect of these items, are reflected in our Consolidated Statement of Comprehensive Income. This net change is recorded as accumulated other comprehensive income in the capitalization section of our balance sheet and does not affect net income or earnings per share. All of these contracts have been designated as cash flow hedges. The unrealized gains and losses accumulated in other comprehensive income are reclassified to fuel, or interest expense, in the periods in which the hedged transaction is actually realized or no longer qualifies for hedge accounting.

The following table sets forth the pre-tax gains/(losses) of our natural gas and interest rate contracts settled and reclassified, the pre-tax change in the fair market value (FMV) of our open contracts and the tax effect in Other Comprehensive Income (in millions) for the presented periods ended March 31:

	Three Months Ended						Twelve Months Ended
	2006			2005			2006			2005
Natural gas contracts settled (1)	$	(0.9	)	$	0.0		$	(5.3	)	$	(8.6	)
Interest rate contracts settled	0.0			0.0			1.4			0.0
Total contracts settled	$	(0.9	)	$	0.0		$	(3.9	)	$	(8.6	)
Change in FMV of open contracts natural gas for natural gas	$	(6.0	)	$	11.8		$	11.1		$	13.6
Change in FMV of open contracts interest rates for interest rates	0.0			0.0			(1.4		)	0.0
Total change in FMV of open contracts	$	(6.0	)	$	11.8		$	9.7		$	13.6
Taxes - natural gas	$	2.6		$	(4.5	)	$	(2.2	)	$	(1.9	)
Taxes - interest rates	0.0			0.0			0.0			0.0
Total taxes	$	2.6		$	(4.5	)	$	(2.2	)	$	(1 .9	)
Total change in OCI — net of tax	$	(4.3	)	$	7.3		$	3.6		$	3.1

(1) Reflected in fuel expense

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Our average cost for our open natural gas hedges increased from $5.810/Dth at December 31, 2005 to $5.863/Dth at March 31, 2006.

We had entered into an interest rate derivative contract in May 2005 to hedge against the risk of a rise in interest rates impacting our 5.8% Senior Notes due 2035 prior to their issuance on June 27, 2005. Costs associated with the interest rate derivative (primarily due to interest rate fluctuations) amounted to approximately $1.4 million and were recorded as a regulatory asset and are being amortized over the life of the 2035 Notes. The $1.2 million redemption premium paid in connection with the redemption of the $30 million aggregate principal amount of our First Mortgage Bonds, 7.75% Series due 2025 redeemed in June 2005, together with $2.4 million of remaining unamortized loss on reacquired debt and $0.3 million of unamortized debt expense, were recorded as a regulatory asset and are being amortized as interest expense over the life of the 2035 Notes.

Competition

In October 2003 and October 2004, we filed notices of intent with the Southwest Power Pool (SPP) for the right to withdraw from the SPP effective October 31, 2004 and October 31, 2005, respectively. Such notices were given because of uncertainty surrounding the treatment from the states regarding RTO participation and cost recoveries. Such withdrawal requires approval from the FERC. We retained the option, however, to rescind such notices, which we have done. In October 2005, we filed a new notice of intent with the SPP for the right to withdraw from the SPP effective October 31, 2006. We are seeking authorizations from Missouri, Kansas and Arkansas for continued participation in and transfer of functional control of our transmission facilities to the SPP RTO should we decide to remain a member. A formal independent RTO Cost Benefit Analysis (CBA) was commissioned and overseen by the Regional State Committee (RSC) of the SPP. The RSC is made up of public service commissioners from several states in the SPP footprint. This CBA, which indicates a positive net benefit for our participation in the SPP RTO for the period 2006 through 2014, was included and submitted as part of the applications to the states from which we have sought authorization. We filed a Stipulation and Agreement between ourselves, the MPSC staff, OPC, and SPP in February 2006 for authorization for the transfer of functional control of our transmission facilities to the SPP RTO and continued participation in the SPP RTO. The specific rules of SPP’s market design, which has now been delayed by FERC order until at least October 1, 2006, have not been finalized and our proceedings in some of the aforementioned states are pending. Additional filings will be required by the SPP prior to final approval by the FERC. As a result, we are unable to quantify the potential impact of membership in the RTO on our future financial position, results of operation or cash flows at this time, but will continue to evaluate the situation and make a decision whether or not to continue membership with the SPP.

The SPP was scheduled to begin operation of an Energy Imbalance Service (EIS) market beginning May 1, 2006. However, by order of the FERC, this market has been delayed until at least October 2006, pending further development and resolution of remaining issues. This EIS market will provide imbalance energy for participating members within the SPP regional footprint. Imbalance energy prices will be based on market participant bids. In addition to energy imbalance service, the SPP will perform a security-constrained economic dispatch of all generation voluntarily offered into the EIS market to the market participants.

LIQUIDITY AND CAPITAL RESOURCES

Our net cash provided by operations was lower during the first quarter of 2006 as compared to the same period in 2005 mainly due to decreased accounts payable and accrued liabilities.

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Investments were higher due to increased construction. Our primary sources of cash flow during the first quarter of 2006 were $18.4 million in internally generated funds and $4.7 million in proceeds from short-term borrowings. Our primary uses of cash during the first quarter of 2006 were $28.1 million in capital expenditures and $8.4 million in dividend payments.

Cash Provided by Operating Activities

Our net cash flows provided by operating activities decreased $5.4 million during the first quarter of 2006 as compared to the first quarter of 2005, despite a $1.9 million increase in net income. Cash flows were negatively impacted primarily by a $13.5 million decrease in accounts payable and accrued liabilities and a $2.4 million decrease in fuel, material and supplies, partially offset by an $11.9 million increase in accounts receivable.

Capital Requirements and Investing Activities

Our net cash flows used in investing activities increased $12.4 million during the first quarter of 2006 as compared to the first quarter of 2005, primarily reflecting additions to our transmission and distribution systems and construction expenditures for the new combustion turbine at Riverton and for our investment in the Plum Point Power Plant.

Our capital expenditures totaled approximately $28.1 million during the first quarter of 2006 compared to approximately $15.7 million for the same period in 2005. These capital expenditures include AFUDC, increases in capitalized software costs, capital expenditures to retire assets and benefits from salvage.

A breakdown of the capital expenditures for the first quarter of 2006 is as follows:

	Quarter Ended March 31, 2006
	(in millions)
Distribution and transmission system additions	$	10.3
Additions and replacements — Asbury	0.7
Additions and replacements — Riverton, Iatan, Ozark Beach, Energy Center, State Line and State Line Combined Cycle	0.4
New generation — Riverton combustion turbine	4.7
New generation — Plum Point Power Plant	9.2
Fiber optics (non-regulated)	0.6
Transportation	0.1
Storms	0.8
Other non-regulated capital expenditures	0.1
Other	0.6
Retirements and salvage (net)	0.6
Total	$	28.1

Approximately 35.9% of our cash requirements for capital expenditures during the first quarter of 2006 were satisfied internally from operations (funds provided by operating activities less dividends paid). We currently expect that internally generated funds will provide approximately 60% of the funds required for the remainder of our budgeted 2006 capital expenditures. We intend to utilize a combination of short-term debt, the proceeds of sales of long-term debt and/or common stock (including common stock sold under our Employee Stock Purchase Plan, our Dividend Reinvestment and Stock Purchase Plan, and our 401(k) Plan and ESOP) to finance additional amounts needed beyond those provided by operating activities for such capital expenditures as well as the acquisition of the gas properties. We will continue to utilize short-term debt as needed to support normal operations or other temporary requirements.

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Financing Activities

Our net cash flows used in financing activities decreased $12.8 million during the first quarter of 2006 as compared to the first quarter of 2005 resulting in a $2.9 million use of cash in the current year. Our net cash flows used in financing activities were primarily affected by increased proceeds from short-term debt in 2006 as compared to 2005.

On April 1, 2005, we redeemed our $10 million First Mortgage Bonds, 7.60% Series due April 1, 2005, using short-term debt. On June 27, 2005, we issued $40 million aggregate principal amount of our Senior Notes, 5.8% Series due 2035, for net proceeds of approximately $39.4 million less $0.1 million of legal fees. We used the net proceeds from this issuance to redeem all $30 million aggregate principal amount of our First Mortgage Bonds, 7.75% Series due 2025 for approximately $31.3 million, including interest and a redemption premium, and to repay short-term debt. The $1.2 million redemption premium paid in connection with the redemption of these first mortgage bonds, together with $2.4 million of remaining unamortized loss on reacquired debt and $0.3 million of unamortized debt expense, were recorded as a regulatory asset and are being amortized as interest expense over the life of the 2035 Notes. We had entered into an interest rate derivative contract in May 2005 to hedge against the risk of a rise in interest rates impacting the 2035 Notes prior to their issuance. Costs associated with the interest rate derivative (primarily due to interest rate fluctuations) amounted to approximately $1.4 million and were recorded as a regulatory asset and are being amortized over the life of the 2035 Notes.

We have an effective shelf registration statement with the SEC under which $400 million of our common stock, unsecured debt securities, preference stock and, subject to receipt of state regulatory approval, first mortgage bonds are available for issuance. Of that amount, $200 million is available for first mortgage bonds. We plan to use a portion of the proceeds from issuances under this new shelf to fund a portion of our proposed acquisition of the Missouri natural gas distribution operations from Aquila, Inc. and a portion of the capital expenditures for our new generation projects.

On July 15, 2005, we entered into a $150 million unsecured revolving credit facility until July 15, 2010. Borrowings (other than through commercial paper) are at the bank’s prime commercial rate or LIBOR plus 80 basis points based on our current credit ratings and the pricing schedule in the line of credit facility. On March 14, 2006, we entered into the First Amended and Restated Unsecured Credit Agreement which amends and restates the $150 million unsecured revolving credit facility. The principal amount of the credit facility was increased to $226 million, with the additional $76 million allocated to support a letter of credit issued in connection with our participation in the Plum Point Power Plant project. This extra $76 million of availability will reduce over the next four years in line with the amount of construction expenditures we owe for Plum Point. The credit facility is used for working capital, general corporate purposes and to back-up our use of commercial paper. This facility requires our total indebtedness (which does not include our note payable to the securitization trust) 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) to be at least two times our interest charges (which includes interest on the note payable to the securitization trust) for 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 the credit facility and will prohibit us from borrowing funds thereunder. As of March 31, 2006, we are in compliance with these ratios. This credit facility is also subject to cross-default if we default on in excess of $10 million in the aggregate on our other indebtedness. This arrangement does not serve to legally restrict the use of our cash in the normal course of operations. There was $46.0 million in outstanding borrowings

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under this agreement at March 31, 2006. There was no outstanding commercial paper at March 31, 2006.

Restrictions in our mortgage bond indenture could affect our liquidity. The Mortgage contains a requirement that for new first mortgage bonds to be issued, our net earnings (as defined in the Mortgage) for any twelve consecutive months within the fifteen months preceding issuance must be two times the annual interest requirements (as defined in the Mortgage) on all first mortgage bonds then outstanding and on the prospective issue of new first mortgage bonds. Our earnings for the twelve months ended March 31, 2006 would permit us to issue approximately $258.2 million of new first mortgage bonds based on this test with an assumed interest rate of 6.5%.

As of March 31, 2006, our corporate credit rating and the ratings for our securities were as follows:

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

On September 22, 2005, Standard & Poor’s (S&P), reflecting our announcement of our proposed acquisition of Aquila, Inc.’s Missouri natural gas properties, placed our corporate credit rating on credit watch with negative implications. S&P stated that the acquisition comes in addition to our embarking on a capital spending program that is significantly higher than historical levels and will be partially debt financed. In addition, S&P stated that the pressure of currently high commodity prices on our cash flow relative to the level in rate recovery could cause a weakening of credit protection measures during a period when our debt levels are increasing as an additional factor in their decision. On February 13, 2006, S&P removed our corporate credit rating from credit watch, but placed us on negative outlook. S&P also reduced the rating on our commercial paper from A-2 to A-3 on February 21, 2006. This reduction has made it more difficult for us to issue commercial paper and, as a result, our short-term debt since then has been in the form of borrowings under our revolving credit facility. However, we are currently researching options that may enable us to issue commercial paper at the current rating. Moody’s affirmed our ratings on May 13, 2005 and revised their rating outlook on us from negative to stable.

These ratings indicate the agencies’ assessment of our ability to pay interest, distributions, dividends and principal on these securities. The lower the rating the higher our financing costs will be when our securities are sold. Ratings below investment grade (investment grade is Baa3 or above for Moody’s and BBB- or above for Standard & Poor’s) may also impair our ability to issue short-term debt, commercial paper or other securities or make the marketing of such securities more difficult.

InSeptember 2005 we entered into an agreement with Fitch Ratings to initiate coverage of us and to assign ratings to our outstanding debt securities. On December 19, 2005, Fitch Ratings initiated coverage and assigned ratings (see table above) with a stable rating outlook. Fitch announced that their ratings reflect our low business risk position as a regulated electric utility, a stable service territory and a seemingly improving regulatory environment in Missouri where we receive approximately 89% of our electric revenues.

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CONTRACTUAL OBLIGATIONS

Set forth below is information summarizing our contractual obligations as of March 31, 2006. Not included in these amounts are expected obligations associated with the Plum Point Power Plant construction and the installation of the new combustion turbine at Riverton for which purchase orders have not been opened, postretirement benefit funding or any future pension funding commitments.

	Payments Due by Period (in millions)
Contractual Obligations (1)	Total		Less than 1 Year		1-3 Years		3-5 Years		More than 5 Years
Long-term debt (w/o discount)	$	358.1	$	—	$	—	$	70.0	$	288.1
Note payable to securitization trust	50.0		—		—		—		50.0
Interest on long-term debt	418.6		26.0		52.4		46.1		294.1
Short-term debt	46.0		46.0		—		—		—
Capital lease obligations	1.4		0.3		0.6		0.5		—
Operating lease obligations (2)	2.4		0.8		1.4		0.2		—
Purchase obligations (3)	365.7		77.1		107.2		69.4		112.0
Open purchase orders	28.0		20.4		7.0		0.6		—
Other long-term liabilities (4)	6.4		0.5		2.2		0.3		3.4
Total Contractual Obligations	$	1,276.6	$	171.1	$	170.8	$	187.1	$	747.6

(1) Some of our contractual obligations have price escalations based on economic indices, but we do not anticipate these escalations to be significant.

(2) Excludes payments under our Elk River Wind Farm agreement, as payments are contingent upon output of the facility. Payments can run from zero up to a maximum of $15.2 million per year based on a 20 year average cost and an annual output of 550,000 megawatt hours.

(3) Includes fuel and purchased power contracts and associated transportation costs, as well as purchased power for 2010 through 2015 for Plum Point.

(4) Other Long-term Liabilities primarily represents electric facilities charges owed to City Utilities of Springfield, Missouri of $11,000 per month over 30 years starting in January 2007, as well as 100% of the long-term debt issued by Mid-America Precision Products, LLC. As of March 31, 2006, EDE Holdings, Inc. was the 52% guarantor of a $2.2 million note included in this total amount.

As noted above, the table above does not include our remaining obligations for the construction of the Plum Point Power Plant which are estimated to be approximately $75 million.

DIVIDENDS

Holders of our common stock are entitled to dividends if, as, and when declared by the Board of Directors, out of funds legally available therefore, subject to the prior rights of holders of any outstanding cumulative preferred stock and preference stock. Payment of dividends is determined by our Board of Directors after considering all relevant factors, including the amount of our retained earnings (which is essentially our accumulated net income less dividend payouts). As of March 31, 2006, our retained earnings balance was $12.9 million, compared to $20.6 million as of March 31, 2005, after paying out $8.4 million in dividends during the first quarter of 2006. A reduction of our dividend per share, partially or in whole, could have an adverse effect on our common stock price.

Our diluted earnings per share were $0.06 for the quarter ended March 31, 2006 and were $0.92 and $0.86 for the years ended December 31, 2005 and 2004, respectively. Dividends paid per share were $0.32 for the three months ended March 31, 2006 and $1.28 for each of the years ended December 31, 2005 and 2004.

In addition, the Mortgage and our Restated Articles contain certain dividend restrictions. The

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most restrictive of these is contained in the Mortgage, which provides that we may not declare or pay any dividends (other than dividends payable in shares of our common stock) or make any other distribution on, or purchase (other than with the proceeds of additional common stock financing) any shares of, our common stock if the cumulative aggregate amount thereof after August 31, 1944 (exclusive of the first quarterly dividend of $98,000 paid after said date) would exceed the earned surplus (as defined in the Mortgage) accumulated subsequent to August 31, 1944, or the date of succession in the event that another corporation succeeds to our rights and liabilities by a merger or consolidation. As of March 31, 2006, our level of earned surplus did not prevent us from issuing dividends. In addition, under certain circumstances (including defaults thereunder), our Junior Subordinated Debentures, 8-1/2% Series due 2031, reflected as a note payable to securitization trust on our balance sheet, held by Empire District Electric Trust I, an unconsolidated securitization trust subsidiary, may also restrict our ability to pay dividends on our common stock.

OFF-BALANCE SHEET ARRANGEMENTS

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

CRITICAL ACCOUNTING POLICIES

See “Item 7 — Managements Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report Form 10-K for the year ended December 31, 2005 for a discussion of our critical accounting policies. There were no changes in these policies in the quarter ended March 31, 2006.

RECENTLY ISSUED ACCOUNTING STANDARDS

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

Item 3. Quantitative and Qualitative Disclosures about Market Risk

Market risk is the exposure to a change in the value of a physical asset or financial instrument, derivative or non-derivative, caused by fluctuations in market variables such as interest rates or commodity prices. Wehandle our commodity market risk in accordance with our established Energy Risk Management Policy, which may include entering into various derivative transactions. We utilize derivatives to manage our gas commodity market risk and to help manage our exposure resulting from purchasing most of our natural gas on the volatile spot market for the generation of power for our native-load customers. See Note 3 of “Notes to Consolidated Financial Statements (Unaudited)” under Item 1 for further information.

Interest Rate Risk. We are exposed to changes in interest rates as a result of financing through our issuance of commercial paper and other short-term debt. We manage our interest rate exposure by limiting our variable-rate exposure (applicable to commercial paper and borrowings under our unsecured credit agreement) to a certain percentage of total capitalization, as set by policy, and by monitoring the effects of market changes in interest rates.

If market interest rates average 1% more in 2006 than in 2005, our interest expense would increase, and income before taxes would decrease by less than $350,000. This amount has been determined by considering the impact of the hypothetical interest rates on our highest month-end commercial paper balance for 2005. These analyses do not consider the effects of the reduced level

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of overall economic activity that could exist in such an environment. In the event of a significant change in interest rates, management would likely take actions to further mitigate its exposure to the change. However, due to the uncertainty of the specific actions that would be taken and their possible effects, the sensitivity analysis assumes no changes in our financial structure.

Commodity Price Risk. We are exposed to the impact of market fluctuations in the price and transportation costs of coal, natural gas, and electricity and employ established policies and procedures to manage the risks associated with these market fluctuations, including utilizing derivatives for gas.

We satisfied 62.2% of our 2005 generation fuel supply need through coal. Approximately 88% of our 2005 coal supply was Western coal. We have contracts and have accepted binding proposals to supply fuel for our coal plants through 2007. These contracts and accepted proposals satisfy approximately 92% of our anticipated fuel requirements for 2006, and 63% of our 2007 requirements for our Asbury and Riverton coal plants. In order to manage our exposure to fuel prices, future coal supplies will be acquired using a combination of short-term and long-term contracts.

We are exposed to changes in market prices for natural gas we must purchase to run our combustion turbine generators. Our natural gas procurement program is designed to minimize our risk from volatile natural gas prices. We enter into physical forward and financial derivative contracts with counterparties relating to our future natural gas requirements that lock in prices (with respect to predetermined percentages of our expected future natural gas needs) in an attempt to lessen the volatility in our fuel expense and improve predictability. We expect that increases in gas prices will be partially offset by realized gains under financial derivative transactions. As of April 28, 2006, 85% of our anticipated volume of natural gas usage for the remainder of year 2006 is hedged at an average price of $5.717 per Dth.

Based on our expected natural gas purchases for 2006, if average natural gas prices should increase 10% more in 2006 than the price at December 31, 2005, our natural gas expense would increase, and income before taxes would decrease by approximately $1.6 million based on our 2006 financial hedge positions.

Credit Risk. Credit risk is the risk of financial loss to the Company if counterparties fail to perform their contractual obligations. In order to minimize overall credit risk, we maintain credit policies, including the evaluation of counterparty financial condition and the use of standardized agreements that facilitate the netting of cash flows associated with a single counterparty. In addition, certain counterparties make available collateral in the form of cash held as margin deposits as a result of exceeding agreed-upon credit exposure thresholds or may be required to prepay the transaction. Amounts reported as margin deposit liabilities represent funds we hold that result from various trading counterparties exceeding agreed-upon credit exposure thresholds. Amounts reported as margin deposit assets represent funds held on deposit by various trading counterparties that resulted from us exceeding agreed-upon credit limits established by the counterparties. As of March 31, 2006 and December 31, 2005, we had margin deposit assets of $2.7 million and $2.1 respectively and margin deposit liabilities of $8.5 million and $7.8 million respectively.

We sell electricity and provide distribution and transmission services to a diverse group of customers, including residential, commercial and industrial customers. Credit risk associated with trade accounts receivable from energy customers is limited due to the large number of customers. In addition, we enter into contracts with various companies in the energy industry for purchases of energy-related commodities, including natural gas in our fuel procurement process.

Our exposure to credit risk is concentrated primarily within our fuel procurement process, as we transact with a smaller, less diverse group of counterparties and transactions may involve large notional volumes and potentially volatile commodity prices. At March 31, 2006, gross credit

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exposure related to these transactions totaled $31.6 million, reflecting the unrealized gains for contracts carried at fair value.

Item 4.  Controls and Procedures

As of the end of the period covered by this report, an evaluation was carried out, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15 of the Securities Exchange Act of 1934. Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective, in all material respects, with respect to the recording, processing, summarizing and reporting, within the time periods specified in the SEC’s rules and forms, of information to be required to be disclosed by us in reports that we file or submit under the Exchange Act.

There have been no changes in our internal control over financial reporting that occurred during the first quarter of 2006 that have materiallyaffected or are reasonably likely to materially affect our internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1-A. 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 ended December 31, 2005.

Item 4. Submission of Matters to a Vote of Security Holders.

(a)           The annual meeting of Common Stockholders was held on April 27, 2006.

(b)The following persons were re-elected Directors of Empire to serve until the 2010 Annual Meeting of Stockholders:

D. Randy Laney (22,955,244 votes for; 401,549 withheld authority).

Myron W. McKinney (22,907,505 votes for; 449,287 withheld authority).

Thomas Mueller (22,948,597 votes for; 408,195 withheld authority).

Mary M. Posner (22,955,346 votes for; 401,446 withheld authority).

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

(c)Common stockholders voted to approve the following proposal:

Ratification of the appointment of PricewaterhouseCoopers LLP as Empire’s independent registered public accounting firm for the fiscal year ending December 31, 2006. Passage of the proposal required the affirmative vote of a majority of the votes cast. The proposal

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received 23,067,833 votes for, which is 88.52% of the outstanding shares and 98.76% of the votes cast.

Item 5. Other Information.

For the twelve months ended March 31, 2006, our ratio of earnings to fixed charges was 2.31x. See Exhibit (12) hereto.

Item 6. Exhibits.

(a)           Exhibits.

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

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

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

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

* This certification accompanies this Report pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and shall not be deemed filed by the Company for purposes of Section 18 or any other provision of the Securities Exchange Act of 1934, as amended.

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SIGNATURES

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

	THE EMPIRE DISTRICT ELECTRIC COMPANY
		Registrant
By		/s/ Gregory A. Knapp
		Gregory A. Knapp
		Vice President — Finance and Chief Financial Officer
By		/s/ Laurie A. Delano
		Laurie A. Delano
		Controller, Assistant Secretary and Assistant Treasurer

May 9, 2006

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EX-12

EXHIBIT (12)

COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES

	Twelve
	Months Ended
	March 31, 2006
Income before provision for income taxes and fixed charges (Note A)	$	68,276,482
Fixed charges:
Interest on first mortgage bonds and secured debt	$	7,846,531
Amortization of debt discount and expense less premium	1,969,064
Interest on short-term debt	570,858
Interest on unsecured long-term debt	14,059,458
Interest on note payable to securitization trust	4,250,000
Other interest	750,559
Rental expense representative of an interest factor (Note B)	51,480
Total fixed charges	29,497,950
Ratio of earnings to fixed charges	2.31x

NOTE A:For the purpose of determining earnings in the calculation of the ratio, net income has been increased by the provision for income taxes, non-operating income taxes, minority interest and by the sum of fixed charges as shown above.

NOTE B:One-third of rental expense (which approximates the interest factor).

EX-31.(A)

Exhibit (31)(a)

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

PURSUANT TO SECTION 302 OF THE

SARBANES-OXLEY ACT OF 2002

I, William L. Gipson, certify that:

1. I have reviewed this quarterly report on Form 10-Q of The Empire District Electric Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the period presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15(d)-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting, which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 9, 2006

By:	/s/ William L. Gipson
	Name: William L. Gipson
	Title: President and Chief Executive Officer

EX-31.(B)

Exhibit (31)(b)

CERTIFICATION OF CHIEF FINANCIAL OFFICER

PURSUANT TO SECTION 302 OF THE

SARBANES-OXLEY ACT OF 2002

I, Gregory A. Knapp, certify that:

1. I have reviewed this quarterly report on Form 10-Q of The Empire District Electric Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the period presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15(d)-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 9, 2006

By:	/s/ Gregory A. Knapp
	Name: Gregory A. Knapp
	Title: Vice President - Finance and Chief Financial Officer

EX-32.(A)

Exhibit (32)(a)

Certification Pursuant to 18 U.S.C. Section 1350,

As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

In connection with the Quarterly Report of The Empire District Electric Company (the “Company”) on Form 10-Q for the period ending March 31, 2006 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), William L. Gipson, as Chief Executive Officer of the Company, certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1) The Report fully complies with the requirements of section 13(a) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Company.

By	/s/ William L. Gipson
	Name: William L. Gipson
	Title: President and Chief Executive Officer

Date:       May 9, 2006

A signed original of this written statement required by Section 906 or other document authenticating, acknowledging or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to The Empire District Electric Company and will be retained by The Empire District Electric Company and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.(B)

Exhibit (32)(b)

Certification Pursuant to 18 U.S.C. Section 1350,

As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

In connection with the Quarterly Report of The Empire District Electric Company (the “Company”) on Form 10-Q for the period ending March 31, 2006 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), Gregory A. Knapp, as Chief Financial Officer of the Company, certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1) The Report fully complies with the requirements of section 13(a) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Company.

By	/s/ Gregory A. Knapp
	Name: Gregory A. Knapp
	Title: Vice President - Finance and Chief Financial Officer

Date:       May 9, 2006

A signed original of this written statement required by Section 906 or other document authenticating, acknowledging or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to The Empire District Electric Company and will be retained by The Empire District Electric Company and furnished to the Securities and Exchange Commission or its staff upon request.