EMPIRE DISTRICT ELECTRIC CO - 10-Q Quarterly Report

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)

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

		For the quarterly period ended March 31, 2005 or

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

		For the transition period from to .

Commission file number: 1-3368

THE EMPIRE DISTRICT ELECTRIC COMPANY

(Exact name of registrant as specified in 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 ý No o

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).
Yes ý No o

As of May 1, 2005, 25,815,282 shares of common stock were outstanding.

PART I. FINANCIAL INFORMATION

Item 1. Consolidated Financial Statements

EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)

	Three Months Ended March 31,
	2005			2004
Operating revenues:
Electric	$	73,235,418		$	71,737,363
Water	321,032			336,080
Non-regulated (Note 9)	5,978,477			5,158,380
	79,534,927			77,231,823
Operating revenue deductions:
Fuel	22,751,201			17,095,692
Purchased power	12,115,290			14,066,573
Regulated – other (Note 8)	14,134,827			13,664,207
Non-regulated (Note 9)	6,134,645			5,301,797
Maintenance and repairs	4,800,063			5,182,885
Depreciation and amortization	7,952,996			7,571,967
Provision for income taxes	(95,428		)	857,442
Other taxes	4,575,142			4,486,287
	72,368,736			68,226,850

Operating income	7,166,191			9,004,973
Other income and deductions:
Allowance for equity funds used during construction	20,388			—
Interest income	68,495			18,734
Provision for other income taxes	35,566			45,186
Minority interest	(26,969		)	42,220
Other - non-operating expense	(213,676		)	(234,085		)
	(116,196		)	(127,945		)
Interest charges:
Long-term debt – other	6,151,604			6,160,055
Note payable to securitization trust	1,062,500			1,062,500
Commercial paper	—			8,176
Allowance for borrowed funds used during construction	(33,768		)	(12,119		)
Other	119,320			80,827
	7,299,656			7,299,439
Net income (loss)	$	(249,661	)	$	1,577,589

Weighted average number of common shares outstanding - basic	25,741,887			25,283,414

Weighted average number of common shares outstanding - diluted	25,741,887			25,344,865

Earnings (loss) per weighted average share of common stock - basic	$	(0.01	)	$	0.06

Earnings (loss) per weighted average share of common stock - diluted	$	(0.01	)	$	0.06

Dividends per share of common stock	$	0.32		$	0.32

See accompanying Notes to Consolidated Financial Statements.

	Twelve Months Ended March 31,
	2005			2004
Operating revenues:
Electric	$	304,088,399		$	303,709,973
Water	1,354,268			1,399,223
Non-regulated (Note 9)	22,400,073			20,721,794
	327,842,740			325,830,990
Operating revenue deductions:
Fuel	70,096,052			60,669,562
Purchased power	50,894,334			55,738,675
Regulated – other (Note 8)	53,432,982			51,596,960
Non-regulated (Note 9)	23,805,430			20,977,430
Maintenance and repairs	20,410,808			20,313,411
Depreciation and amortization	31,178,884			29,445,531
Provision for income taxes	10,101,165			13,441,756
Other taxes	18,221,991			17,060,625
	278,141,646			269,243,950

Operating income	49,701,094			56,587,040
Other income and deductions:
Allowance for equity funds used during construction	142,061			—
Interest income	254,941			58,129
Provision for other income taxes	(255,585		)	269,578
Minority interest	238,917			(214,344		)
Other - non-operating income	67,016			53,162
Other - non-operating expense	(948,690		)	(909,411		)
	(501,340		)	(742,886		)
Interest charges:
Long-term debt – other	24,632,361			25,425,361
Note payable to securitization trust	4,250,000			4,250,000
Commercial paper	11,677			536,227
Allowance for borrowed funds used during construction	(119,704		)	(98,798		)
Other	405,137			348,646
	29,179,471			30,461,436
Net income	$	20,020,283		$	25,382,718

Weighted average number of common shares outstanding - basic	25,581,294			23,510,589

Weighted average number of common shares outstanding - diluted	25,626,830			23,563,771

Earnings per weighted average share of common stock - basic	$	0.78		$	1.08

Earnings per weighted average share of common stock - diluted	$	0.78		$	1.08

Dividends per share of common stock	$	1.28		$	1.28

See accompanying Notes to Consolidated Financial Statements.

THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	Three Months Ended March 31,
	2005			2004

Net income (loss)	$	(249,661	)	$	1,577,589
Reclassification adjustments for gains included in net income or reclassified to regulatory asset or liability	(13,200		)	(2,937,630		)
Change in fair market value of open derivative contracts for period	11,840,120			2,448,850
Income taxes	(4,494,230		)	185,737
Net change in unrealized derivative contracts	7,332,690			(303,043		)

Comprehensive income	$	7,083,029		$	1,274,546

	Twelve Months Ended March 31,
	2005			2004

Net income	$	20,020,283		$	25,382,718
Reclassification adjustments for gains included in net income or reclassified to regulatory asset or liability	(8,546,590		)	(10,791,022		)
Change in fair market value of open derivative contracts for period	13,606,670			9,129,816
Income taxes	(1,922,831		)	631,259
Net change in unrealized derivative contracts	3,137,249			(1,029,947		)

Comprehensive income	$	23,157,532		$	24,352,771

See accompanying Notes to Consolidated Financial Statements

EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEET (UNAUDITED)

	March 31, 2005		December 31, 2004
ASSETS
Plant and property, at original cost:
Electric	$	1,228,141,864	$	1,221,384,998
Water	9,302,805		9,201,314
Non-regulated	24,185,284		23,668,864
Construction work in progress	17,494,703		8,653,720
	1,279,124,656		1,262,908,896
Accumulated depreciation and amortization	414,681,804		405,873,917
	864,442,852		857,034,979
Current assets:
Cash and cash equivalents	4,978,687		12,593,369
Accounts receivable - trade, net	20,468,707		20,052,892
Accrued unbilled revenues	6,197,143		7,599,964
Accounts receivable – other (Note 7)	12,229,750		12,874,123
Fuel, materials and supplies	33,034,634		32,044,113
Unrealized gain in fair value of derivative contracts (Note 3)	6,573,220		2,867,550
Prepaid expenses	1,307,477		1,952,236
	84,789,618		89,984,247
Noncurrent assets and deferred charges:
Regulatory assets (Note 6)	51,701,877		52,127,262
Unamortized debt issuance costs	5,774,057		5,881,384
Unrealized gain in fair value of derivative contracts (Note 3)	11,780,750		4,142,900
Prepaid pension asset	12,248,827		13,973,827
Other	4,356,759		4,393,939
	85,862,270		80,519,312
Total Assets	$	1,035,094,740	$	1,027,538,538

CAPITALIZATION AND LIABILITIES:
Common stock, $1 par value, 25,800,786 and 25,695,972 shares issued and outstanding, respectively	$	25,800,786	$	25,695,972
Capital in excess of par value	323,550,252		321,632,092
Retained earnings	20,591,384		29,078,105
Accumulated other comprehensive income, net of income tax (Note 3)	10,106,911		2,774,221
Total common stockholders’ equity	380,049,333		379,180,390
Long-term debt
Note payable to securitization trust	50,000,000		50,000,000
Obligations under capital lease	77,145		122,570
First mortgage bonds and secured debt	140,252,612		140,363,500
Unsecured debt	209,439,372		209,430,556
Total long-term debt	399,769,129		399,916,626
Current liabilities:
Accounts payable and accrued liabilities	30,444,826		36,926,520
Current maturities of long-term debt	10,487,561		10,462,211
Customer deposits	5,928,496		5,724,211
Interest accrued	7,531,183		2,700,402
Taxes accrued	4,131,888		1,411,355
Obligations under capital lease	232,411		239,684
Unrealized loss in fair value of derivative contracts (Note 3)	1,253,300		1,030,100
Other current liabilities	2,068,766		708,643
	62,078,431		59,203,126
Noncurrent liabilities and deferred credits:
Regulatory liabilities (Note 6)	30,004,271		30,225,020
Deferred income taxes	136,265,727		132,694,686
Unamortized investment tax credits	5,044,605		5,041,000
Postretirement benefits other than pensions	7,826,061		8,248,004
Unrealized loss in fair value of derivative contracts (Note 3)	923,400		1,505,800
Minority interest	732,295		705,326
Other	12,401,488		10,818,560
	193,197,847		189,238,396
Total Capitalization and Liabilities	$	1,035,094,740	$	1,027,538,538

See accompanying Notes to Consolidated Financial Statements.

EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED STATEMENT OF CASH FLOWS (UNAUDITED)

	Three Months Ended March 31,
	2005			2004
Operating activities:
Net income (loss)	$	(249,661	)	$	1,577,589
Adjustments to reconcile net income (loss) to cash flows from operating activities
Depreciation and amortization	9,093,147			8,713,733
Pension expense	1,751,224			739,724
Deferred income taxes, net	(15,735		)	570,471
Investment tax credit, net	3,605			(29,167		)
Allowance for equity funds used during construction	(20,388		)	—
Issuance of common stock and stock options for incentive plans	509,380			490,052
Unrealized (gain)/loss on derivatives	124,200			(568,040		)
Cash flows impacted by changes in:
Accounts receivable and accrued unbilled revenues	1,631,379			2,131,555
Fuel, materials and supplies	(990,521		)	(65,535		)
Prepaid expenses and deferred charges	681,939			554,454
Accounts payable and accrued liabilities	2,383,220			698,453
Customer deposits, interest and taxes accrued	7,755,599			7,430,051
Other liabilities and other deferred credits	1,152,761			321,593

Net cash provided by operating activities	23,810,149			22,564,933

Investing activities:
Capital expenditures – regulated	(15,009,728		)	(7,297,032		)
Capital expenditures and other investments – non-regulated	(673,792		)	(602,831		)

Net cash (used) in investing activities	(15,683,520		)	(7,899,863		)

Financing activities:
Proceeds from issuance of common stock	1,513,594			7,668,275
Net (repayments) from short-term borrowings	(8,864,914		)	(21,458,777		)
Dividends	(8,237,060		)	(8,098,927		)
Redemption of first mortgage bonds	(5,000		)	—
Repayments from non-regulated notes payable	(96,858		)	(88,267		)
Other	(51,073		)	(30,730		)

Net cash used in financing activities	(15,741,311		)	(22,008,426		)

Net decrease in cash and cash equivalents	(7,614,682		)	(7,343,356		)

Cash and cash equivalents at beginning of period	12,593,369			13,108,197

Cash and cash equivalents at end of period	$	4,978,687		$	5,764,841

See accompanying Notes to Consolidated Financial Statements.

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, 2004.

The information furnished reflects all adjustments, consisting only of normal recurring adjustments, which are in our opinion necessary to present fairly the results for the interim periods presented. Certain reclassifications have been made to prior year information to conform to the current year presentation.

Note 2 - Recently Issued Accounting Standards

On March 30, 2005, the FASB issued FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (FIN 47). FIN 47 clarifies that an entity must record a liability for a “conditional” asset retirement obligation if the fair value of the obligation can be reasonably estimated. It also clarifies the FASB’s views on when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. FIN 47 is effective for us no later than December 31, 2005. We are in the process of evaluating the impact of this new interpretation. It will likely require the accrual of additional liabilities and could result in increased expense if the costs associated with these additional liabilities are not recovered in electric rates. However, the amount of any additional liabilities cannot yet be determined.

In December 2004, the FASB issued Statement of Financial Accounting Standards No. 123 (revised 2004) “Share-Based Payments” (FAS 123(R)). The statement requires companies to record stock option expense in their financial statements based on a fair value methodology beginning no later than the first fiscal quarter 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 currently recognize 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. On April 14, 2005, the SEC approved a new rule for public companies that delays the effective date of FAS 123(R), giving a number of those companies more time to develop their implementation strategies. Except for this deferral of the effective date, the guidance in FAS 123(R) is unchanged. FAS 123(R) will now be effective for us on January 1, 2006. We do not expect the adoption of this standard to have a material impact on our financial statements.

See Note 1 under “Notes to Consolidated Financial Statements” in our Annual Report on Form 10-K for the year ended December 31, 2004 for further information regarding recently issued accounting standards.

Note 3 – Risk Management and Derivative Financial Instruments

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

We have recorded the following assets and liabilities (in millions) representing the fair value of qualifying derivative financial instruments held as of March 31, 2005 and December 31, 2004 and subject to the reporting requirements of FAS 133:

	March 31, 2005		December 31, 2004
Current assets	$	6.6	2.9
Noncurrent assets	11.8		4.1

Current liabilities	1.3		1.0
Noncurrent liabilities	0.9		1.5

A $10.1 million, net of tax, unrealized gain representing the fair market value of the effective position of these contracts is recognized as Accumulated Other Comprehensive Income in the capitalization section of the balance sheet. The total tax effect of $6.2 million on this gain is recorded as $4.1 million in deferred taxes and $2.1 million in other current liabilities. These amounts will be adjusted cumulatively on a monthly basis during the determination periods beginning April 1, 2005 and ending on September 30, 2011. At the end of each determination period, any unrealized gain or loss for that period related to the instrument will be reclassified to fuel expense.

We record unrealized gains/(losses) on the overhedged portion of our gas hedging activities, if any, 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 our hedging activities included in “Fuel” (in millions) for each of the periods ended March 31:

	First Quarter				Twelve Months Ended
	2005		2004		2005		2004
Overhedged Portion	$	0.2	$	0.1	$	0.8	$	0.6
Qualified Portion	$	0.0	$	2.9	$	8.5	$	8.4

As of April 22, 2005, 62% of our anticipated volume of natural gas usage for the remainder of year 2005 is hedged at an average price of $4.516 per Dekatherm (Dth). In addition, the following percentages of our anticipated volume of natural gas usage for the next six years are hedged at the following average prices per Dth:

Year	% Hedged		Average Price
2006	35	%	$	4.604
2007	36	%	$	4.526
2008	21	%	$	4.569
2009-2011	40	%	$	4.522

Note 4 – Short-Term Borrowings

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. We are in compliance with these ratios as of March 31, 2005. This credit facility is also subject to cross-default if we default on in excess of $5.0 million in the aggregate on our other indebtedness. There were no outstanding borrowings under this agreement at March 31, 2005 or December 31, 2004.

Note 5 – Commitments, Contingencies and Benefits

Pension and Other Employment and Post -Employment Benefits

Based on the performance of our pension plan assets through January 1, 2004 and January 1, 2005, we were not required under the Employee Retirement Income Security Act of 1974 (ERISA) to fund any additional minimum ERISA amounts with respect to 2004 or 2005.

We expect to make OPEB contributions of $6.5 million in 2005, of which $1.6 million has been made as of March 31, 2005.

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

	Pension Benefits						OPEB
	Three months ended March 31
	2005			2004			2005			2004
Service cost	$	0.9		$	0.8		$	0.5		$	0.3
Interest cost	1.7			1.5			1.0			0.8
Expected return on plan assets	(1.9		)	(1.9		)	(0.6		)	(0.5		)
Amortization of prior service cost	0.1			0.1			(0.2		)	(0.2		)
Amortization of transition obligation	—			—			0.3			0.3
Amortization of net loss	0.9			0.2			0.6			0.5
Net periodic benefit cost	$	1.7		$	0.7		$	1.6		$	1.2

	Pension Benefits						OPEB
	Twelve months ended March 31
	2005			2004			2005			2004
Service cost	$	2.9		$	2.6		$	1.8		$	1.1
Interest cost	6.3			6.0			3.1			3.4
Expected return on plan assets	(7.5		)	(6.7		)	(2.0		)	(1.7		)
Amortization of prior service cost	0.6			0.6			(0.6		)	(0.2		)
Amortization of transition obligation	—			—			1.1			1.1
Amortization of net loss	1.6			1.1			1.8			1.6
Net periodic benefit cost	$	3.9		$	3.6		$	5.2		$	5.3

Stock Compensation

We utilize the accounting provisions of FAS 123 “Accounting for Stock-Based Compensation” and recognize compensation expense over the vesting period of stock-based compensation awards based upon the fair-value of the award as of the date of issuance. There were 24,200 stock awards granted in the first quarter of 2005 relating to the performance-based restricted stock award portion of our stock incentive plan. The fair value of these awards is equal to their market price on the date of grant.

The following table summarizes the activity of the stock option portion of our stock incentive plan for the first quarter of 2005.

	Options	Weighted Average Exercise Price
Outstanding, beginning of year	173,100	$	20.45
Granted	39,100	$	22.77
Exercised	69,700	$	20.95
Forfeited	—	—
Outstanding, end of quarter	142,500	$	20.84
Exercisable, end of quarter	—	—

In addition, we issued 10,580 common shares in the first quarter of 2005 relating to our 401(k) Plan matching contributions.

We recognized $0.5 million and $0.7 million in compensation expense for the three month periods ended March 31, 2005 and 2004, respectively, and $2.0 million and $1.5 million in compensation expense for the twelve months ended March 31, 2005 and 2004, respectively, for these plans, as well as our employee stock purchase plan.

Note 6 – Regulatory Matters

All of our regulatory assets have been allowed recovery in the state of Missouri as a result of the March 10, 2005 rate case order. We expect our regulatory assets related to premiums and related costs for reacquisitions and issuance of debt and those related to post-employment benefit cost incurred since our latest rate cases in the other jurisdictions to also be allowed recovery since these items have historically been allowed in our rate cases. In addition, losses and gains on our 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, 2005, our regulatory assets totaled $51.7 million. We had no interest rate derivatives as of March 31, 2005.

Note 7 – Accounts Receivable - Other

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

	March 31, 2005		December 31, 2004
Accounts receivable for meter loops, meter bases, line extensions, highway projects, etc.	$	1.7	$	1.9
Accounts receivable for insurance reimbursement for Energy Center (1)	1.3		1.9
Accounts receivable for non-regulated subsidiary companies	2.9		3.1
Accounts receivable from Westar Generating, Inc. for commonly-owned facility	0.9		0.5
Taxes receivable – overpayment of estimated income taxes	3.6		4.2
Accounts receivable for true-up on maintenance contracts (2)	1.7		1.2
Other	0.1		0.1
Total accounts receivable – other	$	12.2	$	12.9

(1) The $1.3 million accounts receivable for insurance reimbursement for Energy Center at March 31, 2005 relates to $4.1 million of total expenses for repairs to our Unit No. 2 combustion turbine at the Energy Center, less our $1.0 million deductible which was expensed in the first quarter

of 2004, $1.2 million of insurance reimbursement received as of December 31, 2004 and an additional $0.6 million received in the first quarter of 2005. Based on discussion with our insurer, we expect the remaining $1.3 million to be reimbursed by our insurer.

(2) The $1.7 million in accounts receivable for true-up on maintenance contracts represents the quarterly estimated credit from Siemens Westinghouse related to our maintenance contract entered into in July 2001 for the State Line Combined Cycle Unit (SLCC) accrued in the last six months of 2004 and the first three months of 2005. The measurement period for this maintenance contract runs from June 1, 2004 through May 31, 2005. 40% 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, 2005.

Note 8 - 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 millions) for all periods presented ended March 31:

	Three Months Ended 2005		Three Months Ended 2004		Twelve Months Ended 2005		Twelve Months Ended 2004
Transmission and distribution expense	$	1.7	$	2.0	$	7.2	$	8.1
Power operation expense (other than fuel)	2.2		2.7		9.5		9.8
Customer accounts and assistance expense	1.7		1.8		7.0		6.9
Employee pension expense	1.5		0.7		3.8		3.3
Employee healthcare plan	2.5		1.8		8.8		7.1
General office supplies and expense	1.6		1.7		7.5		6.6
Administrative and general expense	2.3		2.3		8.1		8.2
Allowance for uncollectible accounts	0.6		0.7		1.4		1.5
Miscellaneous expense	—		—		0.1		0.1
Total	$	14.1	$	13.7	$	53.4	$	51.6

Note 9 - Non-regulated Businesses

The table below presents information (in millions) about the reported revenues, operating income, net income, capital expenditures, total assets and minority interests of our non-regulated businesses.

	For the quarter ended March 31,
	2005						2004
	Non-Regulated			Total Company			Non-Regulated			Total Company
Statement of Operations Information
Revenues	$	6.1	*	$	79.5		$	5.2	*	$	77.2
Operating income (loss)	(0.3		)	7.2			(0.3		)	9.0
Net income (loss)	(0.4		)	(0.2		)	(0.3		)	1.6
Minority interest**	—			—			—			—

Capital Expenditures
	$	0.7		$	15.7		$	0.6		$	7.9

	As of March 31, 2005						As of December 31, 2004
	Non-Regulated			Total Company			Non-Regulated			Total Company
Balance Sheet Information
Total assets	$	26.0		$	1,035.1		$	25.6		$	1,027.5
Minority interest	(0.7		)	(0.7		)	(0.7		)	(0.7		)

	For the twelve-months-ended March 31,
	2005						2004
	Non-Regulated			Total Company			Non-Regulated			Total Company
Statement of Operations Information
Revenues	$	22.8	*	$	327.8		$	21.1	*	$	325.8
Operating income (loss)	(1.8		)	49.7			(1.0		)	56.6
Net income (loss)	(1.9		)	20.0			(1.3		)	25.4
Minority interest	(0.2		)	(0.2		)	0.2			0.2

Capital Expenditures
	$	2.8		$	49.6		$	2.7		$	43.7

*Includes revenues received from the regulated business that are eliminated in consolidation.

**Minority interest is less than $50,000.

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, 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;

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

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

• operation of our generation facilities;

• legislation;

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

• competition;

• 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;

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

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

• 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.

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

EXECUTIVE SUMMARY

The Empire 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 and have investments in some non-regulated businesses including fiber optics, Internet access, close-tolerance custom manufacturing and customer information system software services through our wholly owned subsidiary, EDE Holdings, Inc. In 2004, 93.0% of our gross operating revenues were provided from the sale of electricity, 0.4% from the sale of water and 6.6% from our non-regulated businesses. There were no significant changes in these percentages for the first quarter of 2005. In April 2005, we were granted a franchise for the water service we provide in Aurora, Missouri.

The primary drivers of our electric operating revenues in any period are: (1) weather, (2) rates we can charge our customers, (3) customer growth and (4) general economic conditions. 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. The utility commissions in the states in which we operate, as well as the 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 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. Customer growth, which is the growth in the number of customers, contributes to the demand for electricity. We expect our annual customer growth to be approximately 1.6% over the next several years. 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, including the transportation thereof, (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 coal and natural gas for our energy supply and 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 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.

During the first quarter of 2005, basic and diluted earnings (loss) per weighted average share of common stock decreased to $(0.01) as compared to $0.06 in the first quarter of 2004 despite an increase in revenues resulting from five days of the March 2005 Missouri rate increase. For the twelve months ended March 31, 2005, basic and diluted earnings per weighted average share of common stock were $0.78 as compared to $1.08 for the twelve months ended March 31, 2004. As reflected in the table below, the primary drivers for the decline were fuel costs.

The following reconciliation of earnings per share between the first quarter of 2004 and the first quarter of 2005 and the twelve months ended March 31, 2004 versus March 31, 2005 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, 2005 and 2004 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 – 2004	$	0.06		$	1.08

Revenues
Electric	$	0.04		$	0.01
Non – Regulated	0.02			0.05
Expenses
Fuel	(0.15		)	(0.26		)
Purchased power	0.05			0.13
Regulated – other (employee health care and pension expense)	(0.04		)	(0.05		)
Regulated – other (all other)	0.03			(0.00		)
Non – Regulated expenses	(0.02		)	(0.08		)
Maintenance and repairs	0.01			(0.00		)
Depreciation and amortization	(0.01		)	(0.05		)
Other taxes	0.00			(0.03		)
Interest charges	0.00			0.04
Other income and deductions	0.00			0.01
Dilutive effect of additional shares	0.00			(0.07		)
Earnings Per Share – 2005	$	(0.01	)	$	0.78

First Quarter Activities

The Missouri Public Service Commission (MPSC) issued a final order on March 10, 2005 approving an annual increase in base rates of approximately $25.7 million, or 9.96%, effective March 27, 2005 as well as an annual Interim Energy Charge (IEC) of approximately $8.2 million effective March 27, 2005 and expiring three years later. For additional information, see “-Results of Operations – Electric Operating Revenues and Kilowatt-Hour Sales - Rate Matters” below.

At March 31, 2005, the construction at our Riverton plant was still on schedule for the installation of our new Siemens V84.3A2 combustion turbine, with a summer rated capacity of 155 megawatts, scheduled to be operational in 2007. Plans are also still on schedule for the proposed Elk River Windfarm to be located in Butler County, Kansas. On December 10, 2004, we entered into a 20-year contract with PPM Energy, to purchase the energy generated at the proposed Elk River

Windfarm. We expect that the amount and percentage of electricity we generate by natural gas will decrease in 2006 and in the immediate future thereafter due to this contract. We anticipate purchasing approximately 550,000 megawatt-hours of energy, or 10% of our annual needs, from the project beginning in December 2005. We anticipate the cost of our on-system generation to also be offset by purchasing less higher-priced power from other suppliers.

On January 24, 2005, Flint Hills Tallgrass Prairie Heritage Foundation, Inc. filed a purported class action complaint in the United States District Court for the District of Kansas (the Court) styled Flint Hills Tallgrass Prairie Heritage Foundation, Inc. v. Scottish Power, PLC, et al., No. 05-1025JTM (D. Kansas), against, among others, The Empire District Electric Company. Also named as defendants in the action are Scottish Power, PLC, PacificCorp, PPM Energy, Inc., Greenlight Energy, Inc. and Elk River Windfarm LLC. The plaintiffs seek various forms of declaratory and injunctive relief under the United States and Kansas Constitutions as well as various statutory and common law bases. Plaintiffs seek, among other things, to enjoin the defendants from any development or operation of industrial wind turbine electric power generation facilities within the Flint Hills Tallgrass Prairie Ecosystem and challenge the tax status of any such facility. The complaint was dismissed with prejudice by the Court on February 11, 2005. A notice of appeal has been filed and plaintiffs appeal brief was filed April 18, 2005. Empire believes this case is without merit and will defend it vigorously.

On April 27, 2005, the Missouri General Assembly passed Bill SB 179 which authorizes the MPSC to grant fuel adjustment clauses for the state of Missouri. The bill has been sent to the Governor for his signature.

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, 2005, compared to the same periods ended March 31, 2004.

Electric Operating Revenues and Kilowatt-Hour Sales

Of our total electric operating revenues during the first quarter of 2005, approximately 45% were from residential customers, 26% from commercial customers, 15% from industrial customers, 5% from wholesale on-system customers, 5% 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 2004.

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 Quarter 2005	First Quarter 2004	% Change*		12 Months Ended 2005	12 Months Ended 2004	% Change*
Residential	494.4	499.4	(1.0	)%	1,698.8	1,716.6	(1.0	)%
Commercial	324.1	330.3	(1.9	)	1,411.0	1,394.0	1.2
Industrial	249.9	253.9	(1.6	)	1,081.4	1,063.2	1.7
Wholesale On-System	75.3	73.2	2.9		307.8	304.3	1.1
Other**	27.1	27.8	(2.3	)	107.4	105.4	1.9
Total On-System	1,170.7	1,184.6	(1.2	)	4,606.4	4,583.5	0.5

	Operating Revenues						Operating Revenues
	($in millions)						($in millions)
	First Quarter 2005***		First Quarter 2004		% Change*		12 Months Ended 2005***		12 Months Ended 2004		% Change*
Residential	$	32.6	$	32.2	1.2	%	$	124.8	$	125.0	(0.2	)%
Commercial	19.4		19.4		0.1		92.4		90.9		1.6
Industrial	11.2		11.2		0.2		51.9		50.9		2.0
Wholesale On-System	3.4		3.2		7.0		13.8		12.9		7.4
Other**	1.8		1.7		2.2		7.6		7.4		2.8
Total On-System	$	68.4	$	67.7	1.0		$	290.5	$	287.1	1.2

*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 five days of the new Missouri electric rates, including approximately $0.1 million of the Interim Energy Charge that is not projected to be refunded to customers. See discussion below.

On-System Electric Transactions

KWh sales for our on-system customers decreased during the first quarter of 2005 over the first quarter of 2004 primarily due to milder temperatures during 2005 as compared to 2004. Total heating degree days (the number of degrees that the average temperature for that period was below 65° F) for the first quarter of 2005 were 5.4% less than the same period last year and 2.8% less than the 20-year average. Despite the decreased kWh sales, revenues for our on-system customers increased approximately $0.7 million. Five days of the March 2005 Missouri rate increase (discussed below) contributed an estimated $0.5 million to revenues while continued sales growth contributed an estimated $1.8 million during the first quarter of 2005 with weather having a negative impact on revenues. Our customer growth was 1.7% in 2004 and 1.6% in 2003 and we expect our annual customer growth to approximate 1.6% over the next several years.

The decrease in residential and commercial kWh sales during the first quarter of 2005 was primarily due to the milder weather conditions with revenues being positively affected by five days of the March 2005 Missouri rate increase.

Industrial kWh sales, which are not particularly weather sensitive, decreased mainly due to a decrease in sales to our oil pipeline pumping customers while associated revenues increased for the first quarter of 2005 reflecting the March 2005 Missouri rate increase.

On-system wholesale kWh sales increased during the first quarter of 2005 due mainly to continued sales growth. 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, 2005, kWh sales to our on-system customers increased slightly with the associated revenues increasing approximately $3.4 million. FERC, Oklahoma and Missouri rate increases (discussed below) contributed an estimated $1.2 million to revenues while continued sales growth contributed an estimated $8.5 million. Weather and other related factors offset these increases with an estimated $6.3 million negative impact on revenues. Residential kWh sales and revenues decreased slightly primarily due to milder temperatures in the first quarter of 2005 and the third and fourth quarters of 2004 as compared to the prior year periods. Commercial and industrial sales and revenues increased during the twelve months ended March 31, 2005 primarily due to continued sales growth and the Oklahoma and Missouri rate increases. On-

system wholesale kWh sales and revenues increased for the twelve months ended March 31, 2005 reflecting continued sales growth, the May 2003 FERC rate increase 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 affecting the revenue comparisons discussed above:

Jurisdiction	Date Requested	Base Annual Increase Granted		Percent Increase Granted		Date Effective
Missouri - Electric	April 30, 2004	$	25,705,500	9.96	%	March 27, 2005
FERC -Electric	March 17, 2003	1,672,000		14.00	%	May 1, 2003
Oklahoma -Electric	March 4, 2003	766,500		10.99	%	August 1, 2003

On March 4, 2003, we filed a request with the Oklahoma Corporation Commission for an annual increase in base rates for our Oklahoma electric customers in the amount of $954,540, or 12.97%. On August 1, 2003 a Unanimous Stipulation and Agreement was approved by the Oklahoma Corporation Commission providing an annual increase in rates for our Oklahoma customers of approximately $766,500, or 10.99%, effective for bills rendered on or after August 1, 2003. This reflects a rate of return on equity (ROE) of 11.27%.

On March 17, 2003, we filed a request with the FERC for an annual increase in base rates for our on-system wholesale electric customers in the amount of $1,672,000, or 14.0%. This increase was approved by the FERC on April 25, 2003 with the new rates becoming effective May 1, 2003.

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%. Prior to the hearings, we were able to settle several miscellaneous issues with other parties to the case. 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 of these 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 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 million. This stipulation became effective on March 27, 2005 as part of the final Missouri Order described below. Therefore, the deferral of these costs will begin 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 $25.7 million, 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 $0.0021 per kilowatt hour of customer usage. The recent extraordinarily high natural gas prices and extreme volatility of natural gas led the MPSC to allow forecasted fuel costs to be used rather than the traditional historical costs in determining the fuel portion of the rate increase. We will be required to refund to our customers any money collected under the IEC in excess of the greater of the actual and prudently incurred costs of fuel and purchased power or the base cost of fuel and purchased power set in rates (the “Excess IEC Amount”). Any portion of the Excess IEC Amount over $10 million will be refunded at the end of two years and the entire Excess IEC Amount not

previously refunded will be refunded at the end of three years. Each refund will include interest at the current prime rate at the time of refund.

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 our rate case. The MPSC denied these applications on April 7, 2005. We have appealed this decision.

On July 14, 2004, we filed a request with the Arkansas Public Service Commission for an annual increase in base rates for our Arkansas electric customers in the amount of $1,428,225, or 22.1%. A hearing was held on April 27, 2005. Any new rates approved as a result of this hearing would go into effect May 14, 2005.

On April 29, 2005, we filed a request with the Kansas Corporation Commission for an increase in base rates for our Kansas electric customers in the amount of $4,181,078, or 24.64%. Any new rates approved as a result of this request will not go into effect until the last quarter of 2005.

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 acustomers, 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:

	2005				2004
	First Quarter		Twelve Months Ended March 31,		First Quarter		Twelve Months Ended March 31,
(in millions)
Revenues	$	4.3	$	11.6	$	3.5	$	14.7
Expenses	2.7		7.1		1.9		9.1
Net	$	1.6	$	4.5	$	1.6	$	5.6

Revenues less expenses were virtually the same for the first quarter of 2005 as compared to 2004 while decreasing for the twelve months ended March 31, 2005 as compared to the same period in 2004. Although we sold more power in the first quarter of 2005 as compared to the same period in 2004, expenses for the first quarter of 2005 increased primarily due to increased fuel costs for the power sold. The decrease in revenues less expenses for the twelve months ended March 31, 2005 as compared to the prior year period resulted primarily from the non-renewal of short-term contracts for firm energy that ran from January 2002 through June 2003. We sold this energy in the wholesale market when it was not required to meet our own customers’ needs during that period. These expenses are included in our discussion of purchased power costs below.

Operating Revenue Deductions

The amounts discussed below are on a pre-tax basis unless otherwise noted.

During the first quarter of 2005, total operating expenses increased approximately $4.1 million (6.1%) compared with the same period last year. Fuel costs increased approximately $5.7 million (33.1%) but were partially offset by a $2.0 million (13.9%) decrease in purchased power costs during the first quarter of 2005. The increase in fuel costs was primarily due to higher prices for both hedged and unhedged natural gas that we burned in our gas-fired units (an estimated $3.8 million) combined with increased generation by our gas fired units in the first quarter of 2005 (an

estimated $1.1 million). Increased coal costs contributed approximately $0.8 million to the total fuel increase. The decrease in purchased power costs primarily reflected a shift from serving our energy needs with purchased power to generating our own power reflecting that it was more economical to run our own generating units during the first quarter of 2005 than to purchase power. The net increase in fuel and purchased power during the first quarter of 2005 as compared to the same period last year was $3.7 million (11.9%). We expect fuel costs to increase in 2005 due to changes in delivered prices resulting from the expiration of our long-term coal and freight contracts. A long-term contract with a subsidiary of Peabody Holding Company, Inc. for the supply of low sulfur Western coal (Powder River Basin) at the Asbury and Riverton Plants expired in December 2004. We signed a new, three-year contract with Peabody on December 15, 2004 that covers approximately 100% of our anticipated 2005 Western coal requirements, approximately 67% of our anticipated 2006 Western coal requirements and approximately 33% of our anticipated Western coal requirements for 2007. Our current contract with Union Pacific Railroad Company and The Kansas City Southern Railway Company which provides for transportation of the Powder River Basin coal expires at the end of June 2005. We signed a new, five-year contract with Burlington Northern and Santa Fe Railway Company and The Kansas City Southern Railway Company on April 8, 2005 that will be effective June 30, 2005. The delivered price of coal under the new contracts is expected to be higher than the 2004 price during the second quarter of 2005, but we expect the delivered price increase to be substantially mitigated beginning in the third quarter of 2005 and continuing through the balance of the year due to a combination of our new coal supply and coal transportation contracts.

Regulated – other operating expenses increased approximately $0.5 million (3.4%) during the first quarter of 2005 as compared to the same period in 2004. Expenses relating to our employee health care plan and our employee pension expense contributed $0.8 million each to this increase. As discussed previously, effective with the second quarter, we will begin deferring a portion of our pension cost into a regulatory asset as authorized in our latest rate case. These increases in regulated – other operating expense were partially offset by a $0.3 million decrease in transmission and distribution expense, a $0.2 million decrease in stock compensation costs and a $0.2 million decrease in customer accounts expense. Although customer accounts expense decreased, we recorded a $0.3 million reserve during the first quarter of 2005 due to the bankruptcy filing of Eagle Picher, one of our industrial customers. We expect Eagle Picher, however, to be an ongoing customer.

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

Maintenance and repairs expense decreased approximately $0.4 million (7.4%) as compared to the first quarter of 2004 when one of the original combustion turbine peaking units at the Energy Center, Unit No. 2, experienced a rotating blade failure on January 7, 2004 which caused damage throughout the machine. We recorded $1 million of expense, which was the amount of our insurance deductible relating to that turbine, in the first quarter of 2004. This $1.0 million decrease in maintenance and repairs expense at the Energy Center in the first quarter of 2005 was partially offset by a $0.7 million increase in maintenance and repairs expense at our Iatan plant due to a scheduled outage in March 2005.

Depreciation and amortization expense increased approximately $0.4 million (5.0%) during the quarter due to increased plant in service. The provision for income taxes decreased approximately $1.0 million during the first quarter of 2005 due to decreased income. Our effective federal and state income tax rate for the first quarter of 2005 was 34.4% as compared to 34.0% for the first quarter of 2004. Other taxes increased slightly during the first quarter of 2005.

During the twelve months ended March 31, 2005, total operating expenses increased approximately $8.9 million (3.3%) compared to the year ago period. Total fuel costs increased approximately $9.4 million (15.5%) during the twelve months ended March 31, 2005 but were

partially offset by a $4.8 million (8.7%) decrease in purchased power costs 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 $5.3 million) and increased generation by both our coal-fired and gas-fired units (an estimated $4.0 million). The decrease in purchased power costs primarily reflected a shift from serving our energy needs with purchased power to generating our own power, reflecting that it was more economical to run our own generating units during the twelve months ended March 31, 2005 than to purchase power. This decrease in purchased power costs also reflects the non-renewal of the short-term contracts for firm energy that ran from January 2002 through June 2003. The net increase in fuel and purchased power during the twelve months ended March 31, 2005 as compared to the same period last year was $4.6 million (3.9%).

Regulated – other operating expenses increased approximately $1.8 million (3.6%) during the twelve months ended March 31, 2005 as compared to the same period last year due primarily to a $1.6 million increase in employee health care expense, an increase of approximately $0.5 million in employee pension expense, a $0.6 million increase in general administrative expense due to costs associated with Sarbanes-Oxley compliance and a $0.3 million increase in labor costs. These increases in regulated – other operating expense were partially offset by a $0.9 million decrease in transmission and distribution expense, a $0.3 million decrease in regulatory commission expense and a $0.3 million decrease in professional services.

Maintenance and repairs expense increased approximately $0.1 million (0.5%) during the twelve months ended March 31, 2005, compared to the year ago period reflecting increases of approximately $0.6 million in transmission and distribution maintenance costs and $0.4 million in maintenance costs for our gas-fired units. The increase in maintenance and repairs expense for our gas-fired units is primarily related to the State Line Combined Cycle unit (SLCC) and reflects, in part, a true-up credit (our share of the credit as 60% owners of the SLCC) received from Siemens Westinghouse in June 2003 related to our maintenance contract for the period July 2002 through June 2003 for the SLCC. These increases were partially offset by an approximate $0.8 million decrease in maintenance costs for our coal-fired units during the twelve months ended March 31, 2005 as compared to the prior year, reflecting the maintenance outages during the second quarter of 2003 when the Iatan Plant underwent a planned boiler outage, the Riverton Plant’s Unit No. 7 had a 12-day scheduled spring maintenance outage and Unit No. 8 had an extended maintenance outage that ran from February 14, 2003 until May 14, 2003. Also, offsetting increased maintenance costs during the twelve months ended March 31, 2005 was an approximate $0.7 million decrease in maintenance costs at the Energy Center compared to the prior year, primarily reflecting the $1 million insurance deductible recorded in the first quarter of 2004 relating to the turbine repairs.

Depreciation and amortization expense increased approximately $1.7 million (5.9%) due to increased plant in service. Provision for income taxes decreased $3.3 million reflecting decreased income during the current period while other taxes increased approximately $1.2 million (6.8%) due to increased property taxes reflecting our additions to plant in service. Our effective federal and state income tax rate for the twelve months ended March 31, 2005 was 34.1% as compared to 34.2% for the same period in 2004.

Non-regulated Items

Our non-regulated businesses, which we operate through our wholly-owned subsidiary EDE Holdings, Inc., include 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 non-regulated businesses for impairment at December 31, 2004, and determined that no impairment exists based on our forecast of future net cash flows.

Failure to achieve forecasted cash flows could result in impairment in the future. We continue to believe that no impairment exists in our non-regulated businesses as of March 31, 2005.

During the first quarter of 2005, total non-regulated operating revenue increased approximately $0.8 million (15.9%) while total non-regulated operating expense increased approximately $0.8 million (15.7%) as compared to the first quarter of 2004. The increase in operating revenue was mainly attributed to MAPP, the close-tolerance custom manufacturing business in which we own a 50.01% interest. The increase in expense was due mainly to the activities of our fiber optics business and to Conversant, a software company in which we own a 100% interest. Conversant markets Customer Watch, an Internet-based customer information system software. Our electric customer, Eagle Picher, which filed for bankruptcy this quarter is also a main customer of MAPP. MAPP was approved as a critical vendor for Eagle Picher, therefore the exposure of potential uncollectible receivables is estimated to be immaterial. MAPP expects Eagle Picher to be an ongoing customer.

Our non-regulated businesses generated a $0.4 million net loss in the first quarter of 2005 as compared to a $0.3 million net loss in the first quarter of 2004.

For the twelve-months ended March 31, 2005, total non-regulated operating revenue increased approximately $1.7 million (8.1%) while total non-regulated operating expense increased approximately $2.8 million (13.5%) compared with the same period in 2004. The increase in revenues for the twelve-month-ended period was primarily due to MAPP and our fiber optics business while the increase in expense was primarily due to MAPP, Conversant and our fiber optics business.

Our non-regulated businesses generated a $1.9 million net loss for the twelve-months ended March 31, 2005 as compared to a $1.3 million net loss for the same period in 2004.

Nonoperating Items

Total allowance for funds used during construction (“AFUDC”) was virtually the same for the first quarter of 2005 as compared to the first quarter of 2004 and increased $0.2 million during the twelve months ended March 31, 2005 as compared to the prior year period.

Total interest charges on long-term debt was virtually the same for the first quarter of 2005 as compared to the first quarter of 2004 and decreased $0.8 million (3.1%) during the twelve months ended March 31, 2005 as compared to the same period in 2004 primarily reflecting the refinancing we accomplished in 2003 by calling higher interest debt issues and replacing them with debt issues at lower interest rates.

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 as the net change in unrealized gain or loss. 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 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 net-of-tax increase/(decrease) and the change in the fair market value (FMV) of our open contracts in Other Comprehensive Income (in millions) for the presented periods ending March 31,:

	Three Months Ended						Twelve Months Ended
	2005			2004			2005			2004
Natural gas contracts settled (1)	$	(0.0	)	$	(2.9	)	$	(8.6	)	$	(8.4	)
Interest rate contracts settled	0.0			0.0			0.0			(2.4		)
Total contracts settled	$	(0.0	)	$	(2.9	)	$	(8.6	)	$	(10.8	)
Change in FMV of open contracts natural gas for natural gas	$	11.8		$	2.4		$	13.6		$	9.1
Change in FMV of open contracts interest rates for interest rates	0.0			0.0			0.0			0.0
Total change in FMV of open contracts	$	11.8		$	2.4		$	13.6		$	9.1
Taxes - natural gas	$	(4.5	)	$	0.2		$	(1.9	)	$	0.6
Taxes - interest rates	0.0			0.0			0.0			0.0
Total taxes	$	(4.5	)	$	0.2		$	(1.9	)	$	0.6
Total change in OCI – net of tax	$	7.3		$	(0.3	)	$	3.1		$	(1.1	)

(1) Reflected in fuel expense

Our average cost for our open natural gas hedges decreased from $4.795/Dth at December 31, 2004 to $4.567/Dth at March 31, 2005.

Environmental

In mid-December 2003, the EPA issued proposed regulations with respect to SO2, NOx and mercury emissions from coal-fired power plants in a proposed rulemaking known as the Clean Air Interstate Rule (CAIR). The final CAIR was issued by the EPA on March 10, 2005 and will affect 28 states, including Missouri, where our Asbury and Iatan plants are located, but excluding Kansas, where our Riverton plant is located. Also in mid-December 2003, the EPA issued the proposed Clean Air Mercury Rule (CAMR) regulations for mercury emissions by power plants under the requirements of the 1990 Amendments to the Clean Air Act. The final CAMR was issued March 15, 2005. It is possible that we may need to make some expenditures as early as 2007 in order to meet the compliance date of January 1, 2009 for mercury analyzers and the mercury emission compliance date of January 1, 2010. The CAIR and the CAMR were issued as a result of delays and setbacks in the legislative process for the President’s Clear Skies Act legislation, which would have imposed different restrictions on SO2, NOx and mercury emissions. The CAIR and the CAMR are not directed to specific generation units, but instead, require the states (including Missouri and Kansas) to develop State Implementation Plans (SIP) within the next 18 months in order to comply with specific NOx, SO2 and/or mercury state-wide annual budgets. Until these plans are finalized, we cannot determine the required emission rates of NOx, SO2 and mercury for the Asbury or Iatan plants in Missouri or the required mercury emission rate for the Riverton plant in Kansas. Also, the SIPs will likely include allowance trading programs for NOx, SO2 and/or mercury that could allow compliance without additional capital expenditures. However, we expect that pollution control equipment required at the Iatan plant by 2015 may include a Selective Catalytic Reduction (SCR) system, a Flue Gas Desulphurization (FGD) system and a Bag House, with our share of the capital cost estimated at $30 million. We expect that pollution control equipment needed at the Asbury plant by 2015 may include a SCR, a FGD and a Bag House at an estimated capital cost of $105 million. At this time we do not anticipate the installation of additional pollution control equipment at the Riverton plant.

Competition

The FERC recently approved a cost allocation plan which allows for 33% of reliability and approved network resource upgrades to be allocated on a regional basis and the remaining 67% to be

allocated to those entities determined to directly benefit from such upgrades. This structure allows for an equitable spreading of costs for transmission upgrades and should promote expansion of the transmission system in the SPP region. Impacts to us have not been determined at this time but are expected to be beneficial for our future transmission needs.

LIQUIDITY AND CAPITAL RESOURCES

Cash Provided by Operating Activities

Our net cash flows provided by operating activities increased $1.2 million during the first quarter of 2005 as compared to the first quarter of 2004, despite a $1.8 million decrease in net income, primarily due to increased fuel costs. Positively impacting cash flows provided by operating activities during the first quarter of 2005 compared to the same period in 2004 were a $1.0 million increase in the accrual for pension expense, a $1.5 million increase due to reduced working capital requirements (primarily as a result of increased accounts payable and accrued liabilities), $0.7 million increase in unrealized gain on derivatives and a $0.4 million increase in depreciation and amortization expense.

Capital Requirements and Investing Activities

Our net cash flows used in investing activities increased $7.8 million during the first quarter of 2005 as compared to the first quarter of 2004, primarily reflecting additions to our transmission and distribution systems and construction expenditures for the new combustion turbine at Riverton.

Our capital expenditures totaled approximately $15.7 million during the first quarter of 2005 compared to approximately $7.9 million for the same period in 2004. These capital expenditures include AFUDC, capital expenditures to retire assets and benefits from salvage.

A breakdown of the capital expenditures for the first quarter of 2005 is as follows:

	Quarter Ended March 31, 2005
	(in millions)
Distribution and transmission system additions	$	8.1
Additions and replacements – Asbury	1.2
Additions and replacements – Riverton, Iatan, Ozark Beach, Energy Center, State Line and State Line Combined Cycle	0.8
New generation – Riverton combustion turbine	4.4
Fiber optics (non-regulated)	0.4
Transportation	0.4
New generation – other	0.3
Other non-regulated capital expenditures	0.3
Other	0.8
Retirements and salvage (net)	(1.0		)
Total	$	15.7

Approximately all of our cash requirements for capital expenditures during the first quarter of 2005 were satisfied internally from operations (funds provided by operating activities less dividends paid). We currently expect that internally generated funds will provide approximately 82% of the funds required for the remainder of our 2005 capital expenditures. As in the past, we intend to utilize short-term debt or the proceeds of sales of long-term debt 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 any additional amounts needed beyond those

provided by operating activities for such capital expenditures. We will continue to utilize short-term debt as needed to support normal operations or other temporary requirements.

Financing Activities

Our net cash flows used in financing activities decreased $6.3 million during the first quarter of 2005 as compared to the first quarter of 2004 resulting in a $15.7 million use of cash in the current year. Our net cash flows used in financing activities were primarily affected by lower borrowing and repayment of short-term debt (commercial paper) in 2005 as compared to 2004.

On December 17, 2003, we sold to the public in an underwritten offering, 2,000,000 newly issued shares of our common stock for $42.3 million. The net proceeds of approximately $40.3 million were used to repay short-term debt and for other general corporate purposes. On January 8, 2004, the underwriters purchased an additional 300,000 shares for approximately $6.1 million to cover over-allotments. The proceeds were added to our general funds.

We have an effective shelf registration statement with the SEC under which approximately $89 million of our common stock, unsecured debt securities, preference stock and first mortgage bonds remain available for issuance.

On October 22, 2004, we extended our $100 million unsecured revolving credit facility until May 31, 2006. Borrowings are at the bank’s prime commercial rate or LIBOR plus 100 basis points based on our current credit ratings and the pricing schedule in the line of credit facility. 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 the 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, amortization and certain other non-cash charges) 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. We were in compliance with these ratios as of March 31, 2005. This credit facility is also subject to cross-default if we default on in excess of $5.0 million in the aggregate of our other indebtedness. There were no outstanding borrowings under this agreement as of March 31, 2005.

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, 2005 would permit us to issue approximately $155.0 million of new first mortgage bonds based on this test with an assumed interest rate of 7.0%.

As of March 31, 2005, the ratings for our securities were as follows:

	Moody’s		Standard & Poor’s
First Mortgage Bonds		Baa1		A-
First Mortgage Bonds - Pollution Control Series		Aaa		AAA
Senior Notes		Baa2		BBB-
Commercial Paper		P-2		A-2
Trust Preferred Securities		Baa3		BB+

On July 22, 2004, Standard & Poor’s notified us that they had upgraded their rating on our first mortgage bonds from BBB to A-. On September 28, 2004, Standard & Poor’s notified us that

they had placed that rating on credit watch with negative implications reflecting, “prospects for erosion of Empire’s pressured financial condition if recent testimony by the MPSC staff in Empire’s pending general rate case is ultimately endorsed by the MPSC.” On March 14, 2005, Standard & Poor’s, reflecting the MPSC’s March 10, 2005 rate order, affirmed its ‘BBB/A-2’ corporate credit rating on us and removed the rating from credit watch with negative implications. The outlook is now stable. Moody’s currently has a negative rating outlook on Empire. 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 (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.

CONTRACTUAL OBLIGATIONS

Set forth below is information summarizing our contractual obligations as of March 31, 2005. Not included in these amounts are expected obligations associated with the installation of the new combustion turbine at Riverton, the wind energy agreement, postretirement benefit funding or any future pension funding commitments.

	Payments Due by Period
	(in millions)
Contractual Obligations	Total		Less than 1 Year		1-3 Years		3-5 Years		More than 5 Years

Long-term debt (w/o discount)	$	358.1	$	10.0	$	—	$	20.0	$	328.1
Note payable to securitization trust	50.0		—		—		—		50.0
Interest on long-term debt	420.8		26.1		51.9		51.0		291.8
Capital lease obligations	0.3		0.2		0.1		—		—
Operating lease obligations	2.5		0.6		1.2		0.7		—
Purchase obligations*	271.6		49.2		83.5		70.4		68.5
Open purchase orders	33.5		15.1		16.9		1.5		—
Other long-term liabilities**	2.9		0.5		2.3		0.1		—

Total Contractual Obligations	$	1,139.7	$	101.7	$	155.9	$	143.7	$	738.4

*includes fuel and purchased power contracts.

**Other Long-term Liabilities primarily represents 100% of the long-term debt issued by Mid-America Precision Products, LLC. As of March 31, 2005, EDE Holdings, Inc. was the 50.01% guarantor of a $2.7 million note included in this total amount.

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.

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, 2004 for a discussion of our critical accounting policies. There were no changes in these policies in the quarter ended March 31, 2005.

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. We handle 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)” 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. We manage our interest rate exposure by limiting our variable-rate exposure (applicable only to commercial paper) 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 2005 than in 2004, our interest expense would increase, and income before taxes would decrease by less than $100,000. This amount has been determined by considering the impact of the hypothetical interest rates on our highest month-end commercial paper balance for 2004. There was no outstanding commercial paper as of March 31, 2005. These analyses do not consider the effects of the reduced level 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.

We have entered into a three-year contract for the purchase of coal in order to manage our exposure to fuel prices. We satisfied 70.5% of our 2004 fuel supply need through coal. Approximately 90% of our 2004 coal supply was Western coal. Our new three-year coal contract satisfies approximately 100% of our anticipated 2005 requirements, approximately 67% of our 2006 requirements and approximately 33% of our anticipated requirements for 2007 for our Asbury and Riverton Western coal needs. 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 22, 2005, 62%, or 3.49 million Dths’s, of our anticipated volume of natural gas usage for the remainder of year 2005 is hedged. See Note 3 of “Notes to Consolidated Financial Statements (Unaudited)” for further information.

Credit Risk. We are exposed to credit risk by our use of derivative financial instruments. Credit risk is the risk that the counterparty might fail to fulfill its performance obligations under contractual terms. Our Risk Management Oversight Committee, which consists of senior management, has adopted credit risk and procedures policies and provides oversight in the monitoring of counterparty creditworthiness.

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 2005 that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.

PART II. OTHER INFORMATION

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

(a) The annual meeting of Common Stockholders was held on April 28, 2005.

(b) The following person was re-elected Director of Empire to serve until the 2008 Annual Meeting of Stockholders:

William L. Gipson (21,656,997 votes for; 1,405,638 withheld authority).

The following persons were elected Directors of Empire to serve until the 2008 Annual Meeting of Stockholders:

Bill D. Helton (21,613,405 votes for; 1,449,230 withheld authority).

Kenneth R. Allen (21,639,808 votes for; 1,422,827 withheld authority).

The term of office as Director of the following other Directors continued after the meeting: D. Randy Laney, Mary M. Posner, Ross C. Hartley, Myron W. McKinney, B. Thomas Mueller, Allan T. Thoms and Julio S. Leon.

The following plans were approved by shareholders:

Amendment to the Employee Stock Purchase Plan

Votes For		Votes Against		Abstentions		Broker Non-Votes		Total Shares Present
11,956,804		713,615		305,033		10,087,183		23,062,635

2006 Stock Incentive Plan

Votes For		Votes Against		Abstentions		Broker Non-Votes		Total Shares Present
10,315,454		2,313,264		346,735		10,087,182		23,062,635

Amended and restated Stock Unit Plan for Directors

Votes For		Votes Against		Abstentions		Broker Non-Votes		Total Shares Present
9,548,548		2,934,308		492,596		10,087,183		23,062,635

Item 5. Other Information.

For the twelve months ended March 31, 2005, our ratio of earnings to fixed charges was 2.03x. 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.

	THE EMPIRE DISTRICT ELECTRIC COMPANY
	Registrant


	By	/s/ Gregory A. Knapp
		Gregory A. Knapp
		Vice President – Finance and Chief Financial Officer


	By	/s/ Darryl L. Coit
		Darryl L. Coit
		Controller, Assistant Secretary and Assistant Treasurer


May 9, 2005

Part I -	Financial Information (Unaudited):

Item 1.	Consolidated Financial Statements:

	a.	Consolidated Statements of Operations

	b.	Consolidated Statement of Comprehensive Income

	c.	Consolidated Balance Sheet

	d.	Consolidated Statement of Cash Flows

	e.	Notes to Consolidated Financial Statements

	Forward Looking 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

	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 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