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, 2004 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, 2004, 25,374,817 shares of common stock were outstanding.

THE EMPIRE DISTRICT ELECTRIC COMPANY

INDEX

Part I -		Financial Information (Unaudited):

Item 1.		Consolidated Financial Statements:

		a. Consolidated Statements of Income

		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.		Changes in 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 and Reports on Form 8-K

Signatures

PART I. FINANCIAL INFORMATION

Item 1. Consolidated Financial Statements

EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

	Three Months Ended March 31,
	2004			2003
Operating revenues:
Electric	$	71,737,363		$	71,288,537
Water	336,080			325,688
Non-regulated	5,158,380			5,291,504
	77,231,823			76,905,729
Operating revenue deductions:
Fuel	17,095,692			8,763,492
Purchased power	14,066,573			18,536,644
Regulated – other (Note 8)	13,783,564			11,820,218
Non-regulated expenses	5,303,997			5,484,521
Maintenance and repairs	5,182,885			4,792,883
Depreciation and amortization	7,571,967			6,814,916
Provision for income taxes	857,442			3,167,685
Other taxes	4,486,287			3,672,919
	68,348,407			63,053,278

Operating income	8,883,416			13,852,451
Other income and deductions:
Interest income	18,734			17,616
Provision for other income taxes	45,186			25,608
Minority interest	42,220			(97,070		)
Other non-operating expense	(234,085		)	(185,376		)
	(127,945		)	(239,222		)
Interest charges:
Long-term debt – other	6,160,055			6,779,381
Note payable to securitization trust	1,062,500			—
Trust preferred distributions by subsidiary holding solely parent debentures	—			1,062,500
Commercial paper	8,176			78,262
Allowance for borrowed funds used during construction	(12,119		)	(195,589		)
Other	80,827			243,496
	7,299,439			7,968,050
Net income applicable to common stock	$	1,456,032		$	5,645,179

Weighted average number of common shares outstanding	25,283,414			22,607,643

Basic and diluted earnings per weighted average share of common stock	$	0.06		$	0.25

Dividends per share of common stock	$	0.32		$	0.32

See accompanying Notes to Consolidated Financial Statements.

	Twelve Months Ended March 31,
	2004			2003
Operating revenues:
Electric	$	303,709,973		$	301,298,783
Water	1,399,223			1,143,465
Non-regulated	20,721,794			15,069,924
	325,830,990			317,512,172
Operating revenue deductions:
Fuel	60,669,562			44,238,406
Purchased power	55,738,675			66,545,575
Regulated – other (Note 8)	51,716,317			44,764,947
Non-regulated expenses	20,979,630			16,571,682
Maintenance and repairs	20,313,411			23,102,920
Depreciation and amortization	29,445,531			26,415,043
Provision for income taxes	13,441,756			16,782,204
Other taxes	17,060,625			16,047,307
	269,365,507			254,468,084

Operating income	56,465,483			63,044,088
Other income and deductions:
Interest income	58,129			75,835
Provision for other income taxes	269,578			93,542
Minority interest	(214,344		)	(239,533		)
Other non-operating income	53,162			115,650
Other non-operating expense	(909,411		)	(845,938		)
	(742,886		)	(800,444		)
Interest charges:
Long-term debt – other	25,425,361			25,140,595
Note payable to securitization trust	1,062,500			—
Trust preferred distributions by subsidiary holding solely parent debentures	3,187,500			4,250,000
Commercial paper	536,227			651,416
Allowance for borrowed funds used during construction	(98,798		)	(665,629		)
Other	348,646			1,161,421
	30,461,436			30,537,803
Net income applicable to common stock	$	25,261,161		$	31,705,841

Weighted average number of common shares outstanding	23,510,589			22,129,912

Basic and diluted earnings per weighted average share of common stock	$	1.07		$	1.43

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,
	2004			2003

Net income	$	1,456,032		$	5,645,179

Reclassification adjustments for gains included in net income	(2,937,630		)	(3,898,858		)
Change in fair market value of open derivative contracts for period	2,448,850			6,086,185
Income taxes	185,737			(831,184		)
Net change in unrealized gain on derivative contracts	(303,043		)	1,356,143

Comprehensive income	$	1,152,989		$	7,001,322

	Twelve Months Ended March 31,
	2004			2003

Net income	$	25,261,161		$	31,705,841

Reclassification adjustments for gains included in net income	(10,791,022		)	(4,926,348		)
Change in fair market value of open derivative contracts for period	9,129,816			13,644,225
Income taxes	631,259			(3,312,793		)
Net change in unrealized gain on derivative contracts	(1,029,947		)	5,405,084

Comprehensive income	$	24,231,214		$	37,110,925

See accompanying Notes to Consolidated Financial Statements

EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEET (UNAUDITED)

	March 31, 2004		December 31, 2003
ASSETS
Plant and property, at original cost:
Electric	$	1,197,561,372	$	1,191,445,355
Water	8,878,091		8,801,483
Non-regulated	21,678,124		21,105,515
Construction work in progress	7,434,332		5,840,870
	1,235,551,919		1,227,193,223
Accumulated depreciation and amortization	401,722,521		393,321,174
	833,829,398		833,872,049
Current assets:
Cash and cash equivalents	5,764,841		13,108,197
Accounts receivable - trade, net	20,704,518		21,946,990
Accrued unbilled revenues	5,170,345		7,784,403
Accounts receivable - other (Note 7)	10,962,277		9,243,073
Fuel, materials and supplies	29,245,472		29,179,937
Unrealized gain in fair value of derivative contracts (Note 3)	11,318,180		11,631,350
Prepaid expenses	1,611,437		2,240,748
	84,777,070		95,134,698
Deferred charges:
Regulatory assets (Notes 4 and 6)	55,405,829		55,977,495
Unamortized debt issuance costs	6,185,702		6,289,783
Unrealized gain in fair value of derivative contracts (Note 3)	2,272,500		567,000
Other	18,326,641		18,991,507
	82,190,672		81,825,785
Total Assets	$	1,000,797,140	$	1,010,832,532

CAPITALIZATION AND LIABILITIES:
Common stock, $1 par value, 25,357,967 and 24,975,604 shares issued and outstanding, respectively	$	25,357,967	$	24,975,604
Capital in excess of par value	314,503,914		306,727,950
Retained earnings	33,205,677		39,848,572
Accumulated other comprehensive income (net) (Note 3)	6,969,662		7,272,705
Total common stockholders’ equity	380,037,220		378,824,831
Long-term debt (Note 4)
Note payable to securitization trust	50,000,000		50,000,000
Obligations under capital lease	254,856		297,655
First mortgage bonds and secured debt	150,622,345		150,692,450
Unsecured debt	209,401,967		209,402,515
	410,279,168		410,392,620
Current liabilities:
Accounts payable and accrued liabilities	26,341,937		34,102,261
Commercial paper	—		13,000,000
Customer deposits	5,308,187		5,251,359
Interest accrued	7,640,892		2,836,241
Taxes accrued	3,957,961		1,389,389
Obligations under capital lease	218,945		205,556
Unrealized loss in fair value of derivatives (Note 3)	1,373,890		583,140
Current maturities of long-term debt	436,663		429,140
	45,278,475		57,797,086
Noncurrent liabilities and deferred credits:
Regulatory liabilities (Notes 4 and 6)	17,301,387		17,600,422
Deferred income taxes	125,769,662		125,065,620
Unamortized investment tax credits	5,551,833		5,581,000
Postretirement benefits other than pensions	8,078,907		8,088,674
Unrealized loss in fair value of derivative contracts (Note 3)	596,900		80,350
Minority interest	1,117,732		1,159,953
Other	6,785,856		6,241,976
	165,202,277		163,817,995
Total Capitalization and Liabilities	$	1,000,797,140	$	1,010,832,532

See accompanying Notes to Consolidated Financial Statements.

EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED STATEMENT OF CASH FLOWS (UNAUDITED)

	Three Months Ended March 31,
	2004			2003
Operating activities:
Net income	$	1,456,032		$	5,645,179
Adjustments to reconcile net income to cash flows from operating activities
Depreciation and amortization	8,713,733			7,612,916
Pension expense	739,724			964,604
Deferred income taxes, net	570,471			2,197,692
Investment tax credit, net	(29,167		)	(89,497		)
Issuance of common stock and stock options for incentive plans	490,052			389,195
Unrealized loss on derivatives	(568,040		)	(84,748		)
Cash flows impacted by changes in:
Accounts receivable and accrued unbilled revenues	2,131,555			10,527,001
Fuel, materials and supplies	(65,535		)	91,706
Prepaid expenses and deferred charges	554,454			(235,910		)
Accounts payable and accrued liabilities	(7,760,324		)	(611,253		)
Customer deposits, interest and taxes accrued	7,430,051			6,604,490
Other liabilities and deferred credits	483,368			(404,438		)
Accumulated provision-rate refunds	—			(18,718,679		)

Net cash provided by operating activities	14,146,374			13,888,258

Investing activities:
Capital expenditures – regulated	(7,336,445		)	(28,462,576		)
Capital expenditures and other investments – non-regulated	(603,636		)	(1,638,096		)

Net cash used in investing activities	(7,940,081		)	(30,100,672		)

Financing activities:
Proceeds from issuance of common stock	8,072,129			1,834,274
Common stock issuance costs	(403,854		)	—
Net (repayments) proceeds from short-term borrowings	(13,000,000		)	10,011,000
Dividends	(8,098,927		)	(7,231,924		)
Long-term debt issuance costs	(1,321		)	(143,741		)
Other	(117,676		)	185,913

Net cash provided by (used in) financing activities	(13,549,649		)	4,655,522

Net decrease in cash and cash equivalents	(7,343,356		)	(11,556,892		)

Cash and cash equivalents at beginning of period	13,108,197			14,439,227

Cash and cash equivalents at end of period	$	5,764,841		$	2,882,335

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, 2003.

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

The FASB issued FASB Interpretation No. 46 “Consolidation of Variable Interest Entities” in January 2003, and issued its deferral in FASB Interpretation No. 46-R, “Consolidation of Variable Interest Entities” (FIN No. 46-R), in December 2003, which addressed the requirements for consolidating certain variable interest entities. FIN No. 46-R applied immediately to variable interest entities created after January 31, 2003. FIN No. 46-R applies to all other variable interest entities as of March 31, 2004, or, in the case of special purpose entities, December 31, 2003. Empire District Trust I, a securitization trust subsidiary of Empire created in March 2001, was consolidated within our financial statements prior to the adoption of FIN No. 46-R. As a result of the application of FIN No. 46-R, we have deconsolidated this securitization trust as of December 31, 2003. Other than a change in presentation, this deconsolidation had no impact on our financial condition or results of operations. We completed the adoption of FIN No. 46-R during the quarter ended March 31, 2004, which had no impact on our consolidated financial statements. Additionally, we have no material variable interests that require disclosure under FIN No. 46-R.

In December 2003, the FASB issued SFAS No. 132 (revised) to improve financial statement disclosures for defined benefit plans. The standard requires more details about plan assets, benefit obligations, cash flows, benefit costs and other relevant information on an annual and interim basis. SFAS No. 132 (revised) became effective for fiscal years ending after December 15, 2003. See Note 5 for related disclosures.

Our postemployment medical plan provides prescription drug coverage for Medicare-eligible retirees. Our accumulated postretirement benefit obligation (APBO) and net cost recognized for other postemployment benefits (OPEB) do not reflect the effects of the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act). The provisions of the Act provide for a federal subsidy for plans that provide prescription drug benefits and meet certain qualifications, and alternatively would allow prescription drug plan sponsors to coordinate with the Medicare benefit. In accordance with FASB staff position No. FAS 106-1, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003”, issued in January 2004, we have elected to defer recognition of the effects of the Act until the earlier of the issuance of final accounting guidance or a significant modification of the plan. We are presently evaluating the impact of the Act on our financial statements.

See Note 1 under “Notes to Consolidated Financial Statements” in our Annual Report on Form 10-K for the fiscal year ended December 31, 2003 for further information regarding recently issued accounting standards.

Note 3 – Risk Management and Derivative Financial Instruments

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

As of March 31, 2004, we have recorded the following assets and liabilities representing the fair value of derivative financial instruments held as of that date and subject to the reporting requirements of FAS 133.

Current assets	$	11,318,180

Noncurrent assets	$	2,272,500

Current liabilities	$	1,373,890

Noncurrent liabilities	$	596,900

A $6,969,662 net of tax, unrealized gain representing the fair market value of these contracts is recognized as Accumulated Other Comprehensive Income in the capitalization section of the balance sheet. The tax effect of $4,271,728 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, 2004 and ending on August 31, 2008. At the end of each determination period, any 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 in “Fuel” under the Operating Revenues Deductions section of our income statements as allowed by FAS 133 since all of our gas hedging activities are related to stabilizing fuel costs as part of our fuel procurement program and are not speculative ventures. Pre-tax gains/(losses) from the overhedged portion of our hedging activities included in “Fuel” were $117,000 and $1.7 million for the quarters ended March 31, 2004 and 2003, respectively, and $614,000 and $2.9 million for the twelve months ended March 31, 2004 and 2003, respectively. See Note 4 – Long-Term Debt (below) for information on our hedging of interest rates.

As of April 16, 2004, 63% of our anticipated volume of natural gas usage for the remainder of year 2004 is hedged at an average price of $3.507 per Dekatherm (Dth). In addition, approximately 40% of our anticipated volume of natural gas usage for the year 2005 is hedged at an average price of $4.147 per Dth, approximately 20% of our anticipated volume of natural gas usage for the year 2006 is hedged at an average price of $4.271 per Dth, approximately 20% of our anticipated volume of natural gas usage for the year 2007 is hedged at an average price of $4.515 per Dth, and approximately 9% of our anticipated volume of natural gas usage for the year 2008 is hedged at an average price of $4.635 per Dth.

Note 4 – Long-Term Debt

On June 17, 2003, we sold to the public in an underwritten offering, $98 million aggregate principal amount of our Senior Notes, 4.5% Series due 2013, for net proceeds of approximately $96.6 million. We used the net proceeds from this issuance, along with short-term debt, to redeem all $100 million aggregate principal amount of our Senior Notes, 7.70% Series due 2004 for approximately $109.8 million, including interest. We had entered into an interest rate derivative contract in May 2003 to hedge against the risk of a rise in interest rates impacting the 2013 Notes prior to their issuance. Costs associated with the interest rate derivative (primarily due to interest rate fluctuations) amounted to approximately $2.7 million and were capitalized as a regulatory asset and are being amortized over the life of the 2013 Notes, along with the $9.1 million redemption premium paid on the Senior Notes, 7.70% Series due 2004.

On November 3, 2003, we issued $62.0 million aggregate principal amount of Senior Notes, 6.70% Series due 2033 for net proceeds of approximately $61.0 million. We used the proceeds from this issuance, along with short-term debt, to redeem three separate series of our outstanding first

mortgage bonds: (1) all $2.25 million aggregate principal amount of our First Mortgage Bonds, 9¾% Series due 2020 for approximately $2.4 million, including interest; (2) all $13.1 million aggregate principal amount of our First Mortgage Bonds, 7¼% Series due 2028 for approximately $13.7 million, including interest; and (3) all $45.0 million aggregate principal amount of our First Mortgage Bonds, 7% Series due 2023 for approximately $46.8 million, including interest. The $1.7 million aggregate redemption premiums paid in connection with the redemption of these first mortgage bonds, together with $1.1 million of remaining unamortized issuance costs and discounts on the redeemed first mortgage bonds, were recorded as a regulatory asset and are being amortized as interest expense over the life of the 2033 Notes. On May 16, 2003, we entered into an interest rate derivative contract with an outside counterparty to hedge against the risk of a rise in interest rates impacting the 2033 Notes prior to their issue. Upon issuance of the 2033 Notes, the realized gain of $5.1 million from the derivative contract was recorded as a regulatory liability and is being amortized over the life of the debt to reduce interest expense.

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, 2003, we were required under the Employee Retirement Income Security Act of 1974 (ERISA) to fund approximately $0.3 million in order to maintain minimum funding levels and contributed this $0.3 million in the first quarter of 2004. We also expected to be required to fund approximately $0.2 million in 2005 based on the performance of plan assets as of November 30, 2003. This amount, however, was an estimate and changed based on actual investment performance at December 31, 2003 and the finalization of actuarial assumptions. Based upon the refinement of this estimate, we believe we will not be required to fund any additional amounts for 2004 and 2005.

Our net periodic pension benefit (cost) or income (related to the application of SFAS 87, “Employers’ Accounting for Pensions”), net of tax, is presented below as a percentage of net income for each of the periods ended March 31, 2004 and 2003:

	% Effect on Net Income
	2004		2003
Three Months Ended	(23.62	)%	(8.13	)%
Twelve Months Ended	(6.81	)%	2.46	%

We expect to make OPEB contributions of $3.4 million in 2004. We have elected to defer recognition of the new Medicare Prescription Drug Improvement and Modernization Act of 2003 and are still evaluating what effect it may have. See Note 2 for further details.

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

	Pension Benefits						OPEB
	Three months ended March 31
	2004			2003			2004			2003
Service cost	$	0.8		$	0.6		$	0.3		$	0.3
Interest cost	1.5			1.5			0.9			0.8
Expected return on plan assets	(1.9		)	(1.6		)	(0.5		)	(0.4		)
Amortization of prior service cost	0.1			0.2			(0.2		)	—
Amortization of transition obligation	—			0.0			0.3			0.3
Amortization of net (gain) loss	0.2			0.3			0.6			0.5
Net periodic benefit cost	$	0.7		$	1.0		$	1.4		$	1.5

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 26,200 stock awards granted in the first quarter of 2004 relating to the performance-based restricted stock award portion of our stock incentive plan.

The following table summarizes the activity of the stock option portion of our stock incentive plan for the first quarter of 2004.

	Options	Weighted Average Exercise Price
Outstanding, beginning of year	118,900	$	19.83
Granted	54,200	$	21.79
Exercised	—	—
Forfeited	—	—
Outstanding, end of quarter	173,100	$	20.45
Exercisable, end of quarter	—	—

In addition, we issued 8,626 shares in the first quarter of 2004 relating to our 401(k) Plan matching contributions.

We recognized $0.4 million and $0.2 million in compensation expense for the three month periods ended March 31, 2004 and 2003, respectively, and $1.1 million and $0.8 million in compensation expense for the twelve months ended March 31, 2004 and 2003, respectively, for these plans, as well as our employee stock purchase plan.

Note 6 – Regulatory Matters

All of our regulatory assets are earning a current return except for those 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 case in each jurisdiction. Cost recovery of debt related costs has historically been allowed in our rate cases. Postretirement benefit costs have also been allowed in rates, pursuant to state statute. We believe it is probable these assets will be afforded similar treatment by our regulators. In addition, losses and gains on interest rate derivatives have also been incurred since our latest rate case. Since these items increase and reduce, respectively, our effective interest cost, we believe it is probable they will be included in our rate base. See Note 4.

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, 2004		December 31, 2003
Accounts receivable for meter loops, meter bases, line extensions, highway projects, etc.	$	2.0	$	1.9
Accounts receivable for insurance reimbursement for Energy Center	1.3		—
Accounts receivable of our non-regulated subsidiary companies	2.0		1.7
Accounts receivable from Westar Generating, Inc. for commonly-owned facility	0.8		0.5
Taxes receivable – overpayment of estimated income taxes	3.0		3.2
Accounts receivable for true-up on maintenance contracts	1.8		1.0
Other	0.1		0.9
Total accounts receivable – other	$	11.0	$	9.2

The $1.3 million accounts receivable for insurance reimbursement for Energy Center is for $2.3 million of expenses related to repairs to our Unit No. 2 combustion turbine at the Energy Center, less our $1 million deductible. We expect for this amount to be reimbursed by our insurer.

The $1.8 million in accounts receivable for true-up on maintenance contracts represents the gross estimated credits accrued in the last six months of 2003 and the first three months of 2004 related to our maintenance contract entered into in July 2001 for the State Line Combined Cycle Unit (SLCC). The measurement period for this maintenance contract runs from June 1, 2003 through May 31, 2004. 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, 2004.

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 income (in millions) for all periods presented ending March 31:

	First Quarter 2004		First Quarter 2003		12 Months Ended 2004		12 Months Ended 2003
Transmission and distribution expense	$	2.0	$	2.0	$	8.1	$	8.4
Power operation expense (other than fuel)	2.7		2.0		9.8		8.9
Customer accounts & assistance expense	1.8		1.6		6.9		6.8
Employee pension expense (income)	0.7		0.9		3.3		(0.9		)
Employee healthcare plan	1.9		1.4		7.2		6.5
General office supplies and expense	1.7		1.4		6.6		5.9
Administrative and general expense	2.3		2.2		8.2		7.5
Allowance for uncollectible accounts	0.7		0.2		1.5		1.3
Miscellaneous expense	—		0.1		0.1		0.4
Total	$	13.8	$	11.8	$	51.7	$	44.8

Note 9 - Non-regulated Businesses

In February 2003, we purchased Joplin.com, a leading Internet service provider in the Joplin, Missouri area. The purchase was made through Transaeris, a non-regulated subsidiary of EDE Holdings, Inc. We have merged Transaeris and Joplin.com into one company named Fast Freedom, Inc.

In September 2003, EDE Holdings, Inc. purchased an approximate 6% interest in ETG, a company that makes automated meter reading equipment. In April, 2004, EDE Holdings, Inc. exercised an option to purchase an additional 6.8% interest in ETG to increase our holdings to approximately 12.8%. This investment is accounted for under the cost method.

The table below presents information 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,
	2004						2003
	Non-Regulated			Total Company			Non-Regulated			Total Company

Statement of Income Information

Revenues	$	5,239,277	*	$	77,231,823		$	5,342,701	*	$	76,905,729
Operating income (loss)	$	(303,784	)	$	8,883,416		$	(274,838	)	$	13,852,451
Net income (loss)	$	(337,643	)	$	1,456,032		$	(418,425	)	$	5,645,179
Minority interest	$	(42,220	)	$	(42,220	)	$	97,070		$	97,070

Capital Expenditures**

	$	603,636		$	8,406,555		$	2,084,445		$	29,780,848

	As of March 31, 2004				As of December 31, 2003
	Non-Regulated		Total Company		Non-Regulated		Total Company

Balance Sheet Information

Total assets	$	24,487,806	$	1,000,797,140	$	24,439,244	$	1,010,832,532
Minority interest	$	1,117,732	$	1,117,732	$	1,159,953	$	1,159,953

	For the twelve-months-ended March 31,
	2004					2003
	Non-Regulated			Total Company		Non-Regulated			Total Company

Statement of Income Information

Revenues	$	21,114,326*		$	325,830,990	$	15,121,121*		$	317,512,172
Operating income (loss)	$	(965,098	)	$	56,465,483	$	(1,317,534	)	$	63,044,088
Net income (loss)	$	(1,311,878	)	$	25,261,161	$	(1,577,194	)	$	31,705,840
Minority interest	$	214,344		$	214,344	$	239,533		$	239,533

Capital Expenditures**

	$	2,673,058		$	43,685,065	$	6,780,605		$	92,339,243

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

**Capital expenditures to retire assets and benefits from salvage are not included here, but are included in capital expenditures on our Consolidated Statements of Cash Flows

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 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 revision of our construction plans and cost estimates; the performance 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 non-regulated businesses including fiber optics, Internet access, utility industry technical training, close-tolerance custom manufacturing and customer information system software services through our wholly owned subsidiary, EDE Holdings, Inc.

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 contributes to the demand for electricity. We expect our annual customer growth to be approximately 1.5% over the next several years.

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 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 2004, basic and diluted earnings per weighted average share of common stock decreased to $0.06 as compared to $0.25 in the first quarter of 2003 despite a slight increase in revenues. Positively impacting earnings approximately $0.03 per share were the May 2003 FERC rate increase and the August 2003 Oklahoma rate increase. An increase in earnings of approximately

$0.05 per share from continued customer growth was offset by an approximate $0.05 per share decrease due to mild weather. A decrease in off-system revenues decreased earnings approximately $0.02 per share. Our first quarter 2004 results were negatively impacted predominantly by a $3.8 million net increase in fuel and purchased power costs, which reduced earnings by approximately $0.11 per share. Also reducing earnings were increases in operations expense, including increased employee health care expense and bad debt expense, totaling approximately $0.03 per share and depreciation and amortization expense and other taxes totaling approximately $0.04 per share. Maintenance and repair costs related to a rotating blade failure at the Energy Center decreased earnings approximately $0.03 per share. The calculation of our earnings per share for the first quarter of 2004 also gives effect to the dilution from the sale of 2.3 million shares of our common stock in December 2003 and January 2004. See “- Liquidity and Capital Resources” below.

For the twelve months ended March 31, 2004, basic and diluted earnings per weighted average share of common stock decreased to $1.07 as compared to $1.43 for the twelve months ended March 31, 2003 despite increased revenues. Positively impacting earnings approximately $0.34 per share were the December 2002 Missouri rate increase, May 2003 FERC rate increase and August 2003 Oklahoma rate increase. An increase in earnings of approximately $0.21 per share from continued customer growth was offset by an approximate $0.21 per share decrease in off system revenues. Mild weather decreased earnings approximately $0.26 per share. Also favorably impacting earnings was a $2.8 million decrease in total maintenance and repairs expense which increased earnings by approximately $0.08 per share. Earnings per share for the twelve months ended March 31, 2004, were negatively impacted predominantly by a $4.2 million net increase in pension expense, a $5.6 million increase in total fuel and purchased power costs and a $7.2 million decrease in off-system revenues, which reduced earnings per share by $0.14, $0.16 and $0.21, respectively. Also negatively impacting earnings were increases in depreciation and amortization expense and other taxes, and maintenance and repairs expense (including the costs related to a rotating blade failure at the Energy Center which caused damage throughout the machine), which decreased earnings per share by approximately $0.12 and $0.08, respectively. The calculation of our earnings per share for the twelve months ended March 31, 2004 also gives effect to the dilution from the sales of 2.3 million shares of our common stock in December 2003 and January 2004 and 2.5 million shares in May 2002. See “- Liquidity and Capital Resources” below.

On April 30, 2004, we filed a request with the Missouri Public Service Commission for an annual increase in base rates for our Missouri electric customers in the amount of $38,282,294, or 14.82%. See “-Rate Matters” below.

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, 2004, compared to the same periods ended March 31, 2003.

Electric Operating Revenues and Kilowatt-Hour Sales

Of our total electric operating revenues during the first quarter of 2004, approximately 45% were from residential customers, 27% from commercial customers, 16% from industrial customers, 4% from wholesale on-system customers, 3% from wholesale off-system transactions and 5% from miscellaneous sources, primarily transmission services. The breakdown of our customer classes has not significantly changed from the first quarter of 2003.

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 2004	First Quarter 2003	% Change*		12 Months Ended 2004	12 Months Ended 2003	% Change*
Residential	499.4	511.2	(2.3	)%	1,716.6	1,755.8	(2.2	)%
Commercial	330.3	323.1	2.2		1,394.0	1,387.2	0.5
Industrial	253.9	249.4	1.8		1,063.2	1,039.6	2.3
Wholesale On-System	73.2	77.5	(5.5	)	304.3	323.9	(6.1	)
Other***	27.8	26.2	5.8		105.4	103.2	2.2
Total On-System	1,184.6	1,187.4	(0.2	)	4,583.5	4,609.7	(0.6	)

	Operating Revenues ($in millions)						Operating Revenues ($in millions)
	First Quarter 2004		First Quarter 2003		*Change%**		12 Months Ended 2004		12 Months Ended 2003		*Change%**
Residential	$	32.2	$	32.4	(0.5	)%	$	125.0	$	123.3	1.4	%
Commercial	19.4		19.0		1.9		90.9		87.2		4.3
Industrial	11.2		10.9		2.0		50.9		48.0		5.9
Wholesale On-System	3.2		2.8		16.0		12.9		11.7		10.2
Other***	1.7		1.7		3.9		7.4		7.0		6.0
Total On-System	$	67.7	$	66.8	1.4		$	287.1	$	277.2	3.6

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

**Revenues exclude amounts collected under the Interim Energy Charge during 2002 and refunded to customers during the first quarter of 2003. See discussion below.

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

On-System Electric Transactions

KWh sales for our on-system customers decreased slightly (0.2%) during the first quarter of 2004 over the first quarter of 2003 primarily due to mild temperatures during 2004 as compared to colder temperatures during 2003, which primarily affected sales to our residential class. Total heating degree days (the number of degrees that the average temperature for that period was below 65° F) for the first quarter of 2004 were actually 1.9% more than the 20-year average but 11.7% less than the same period last year when a new all-time winter peak of 987 megawatts was established on January 23, 2003. Despite the decreased kWh sales, revenues for our on-system customers increased approximately $0.9 million. The Oklahoma and FERC rate increases discussed below and customer growth contributed approximately $1.1 million and $1.7 million, respectively to revenues during the first quarter of 2004 with weather having a negative effect of approximately $1.9 million. Our customer growth was 1.63% in 2003 and we expect our annual customer growth to approximate 1.5% over the next several years.

The decrease in residential kWh sales and revenues during the first quarter of 2004 was primarily due to the milder weather conditions with revenues being positively affected by the August 2003 Oklahoma rate increase.

Commercial and industrial kWh sales and associated revenues increased for the first quarter of 2004 reflecting increased sales mainly due to the customer growth discussed above. Industrial sales benefited mainly from the addition of two new oil pipeline pumping stations on our system that

became fully operational in June 2003. Commercial revenues were also positively affected by the August 2003 Oklahoma rate increase.

On-system wholesale kWh sales decreased during the first quarter of 2004 due mainly to the change in customer status in June 2003 of an on-system wholesale customer/aggregator, comprising three of our on-system wholesale accounts, which elected to go off-system and purchase power from us at market-based rates. Revenues received from these accounts, which comprised 5-6% of our on-system wholesale sales, but less than one-half percent of our total on-system sales in 2002, are now included in our off-system sales. Revenues associated with these FERC-regulated sales increased as a result of the FERC rate increase that became effective May 1, 2003 and as a result of the fuel adjustment clause applicable to such sales. This clause permits the pass through to customers of changes in fuel and purchased power costs.

For the twelve months ended March 31, 2004, kWh sales to our on-system customers decreased approximately 0.6% while the associated revenues increased approximately $9.9 million. Rate increases contributed approximately $11.5 million to revenues with customer growth contributing approximately $7.3 million and weather having a negative effect approximating $8.9 million. Residential kWh sales decreased primarily due to milder temperatures in June 2003, September 2003 and the first quarter of 2004 as compared to the prior year periods. Revenues associated with these sales, however, were positively affected by the August 2003 Oklahoma rate increase, December 2002 Missouri rate increase and July 2002 Kansas rate increase. Commercial and industrial sales and revenues increased during the twelve months ended March 31, 2004 primarily due to the customer growth and rate increases discussed above. On-system wholesale kWh sales decreased for the twelve months ended March 31, 2004 reflecting the change in customer status discussed above while associated revenues increased reflecting the May 2003 FERC rate increase as well as 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	Annual Increase Granted	Percent Increase Granted		Date Effective
Missouri - Electric	November 3, 2000	$17,100,000	8.40	%	October 2, 2001
Missouri - Electric	March 8, 2002	11,000,000	4.97	%	December 1, 2002
Missouri - Water	May 15, 2002	358,000	33.70	%	December 23, 2002
Kansas - Electric	December 28, 2001	2,539,000	17.87	%	July 1, 2002
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

The 2001 Missouri order approved an annual Interim Energy Charge, or IEC, of approximately $19.6 million effective October 1, 2001 and expiring two years later which was collected subject to refund (with interest). The 2002 Missouri electric order called for us to refund all funds collected under the IEC, with interest, by March 15, 2003. The refunds were made in the first quarter of 2003 and did not have a material impact on our earnings in any of the years from 2001 through 2003.

On April 30, 2004, we filed a request with the Missouri Public Service Commission for an annual increase in base rates for our Missouri electric customers in the amount of $38,282,294, or

14.82%. As part of the filing, we asked the Commission to consider, in addition to a traditional ratemaking approach, two options that would allow us to recover our actual fuel and purchased power expenses: an IEC, subject to refund, similar to the one approved in our 2001 case, or a fuel adjustment clause, that would reflect actual fuel prices. Any new rates approved as a result of this request are not expected to be effective until the first 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 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:

	2004				2003
(in millions)	First Quarter		Twelve Months Ended March 31,		First Quarter		Twelve Months Ended March 31,

Revenues	$	3.5	$	14.7	$	4.1	$	22.0
Expenses	1.9		9.1		2.6		13.0
Net	$	1.6	$	5.6	$	1.5	$	9.0

Revenues less expenses were virtually the same in the first quarters of 2004 and 2003. The decrease in revenues less expenses for the twelve months ended March 31, 2004 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.

Operating Revenue Deductions

During the first quarter of 2004, total operating expenses increased approximately $5.3 million (8.4%) compared with the same period last year. Fuel costs increased approximately $8.3 million (95.1%) but were partially offset by a $4.5 million (24.1%) decrease in purchased power costs during the first quarter of 2004. The increase in fuel costs was primarily due to increased generation by our gas fired units, higher prices for the unhedged portion of the natural gas that we burned in these units and to a smaller net gain from our natural gas derivative contracts (which reduces fuel expense) in the first quarter of 2004 ($3.0 million) as compared to the first quarter of 2003 ($4.6 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 first quarter of 2004 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 first quarter of 2004 as compared to the same period last year was $3.8 million (14.1%).

Regulated – other operating expenses increased approximately $2.0 million (16.6%) during the first quarter of 2004 as compared to the same period in 2003. Expenses relating to our employee health care plan contributed $0.4 million to this increase and customer accounts expense added $0.6 million, with $0.4 million of this amount being an addition to bad debt expense. See Note 5 of “Notes to Consolidated Financial Statements (Unaudited)” for information concerning the

percentage of our net income that comprises our net periodic benefit cost related to the application of FAS 87.

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

Maintenance and repairs expense increased approximately $0.4 million (8.1%) as compared to the same period last year primarily due to maintenance on one of the original combustion turbine peaking units at the Energy Center, Unit No. 2, which experienced a rotating blade failure on January 7, 2004 which caused damage throughout the machine. We recorded $1 million of expense, which is the amount of our insurance deductible relating to that turbine, in the first quarter of 2004. Partially offsetting this expense for the insurance deductible was decreased maintenance contracts expense of approximately $0.7 million for the Energy Center, State Line Unit No. 1 and the SLCC. Depreciation and amortization expense increased approximately $0.8 million (11.1%) during the quarter due to increased plant in service. The provision for income taxes decreased approximately $2.3 million during the first quarter of 2004 due to decreased income. Other taxes increased approximately $0.8 million (22.2%) during the first quarter of 2004 due to increased property taxes reflecting our additions to plant in service and an increase in city taxes as compared to the first quarter of 2003 when we had a decrease in city taxes resulting from the refund of the IEC in the first quarter of 2003.

During the twelve months ended March 31, 2004, total operating expenses increased approximately $14.9 million (5.9%) compared to the year ago period. Total fuel costs increased approximately $16.4 million (37.1%) during the twelve months ended March 31, 2004 but were partially offset by a $10.8 million (16.2%) decrease in purchased power costs during the same period. The increase in fuel costs was primarily due to increased generation by both our coal-fired and gas-fired units, reflecting the non-renewal of short-term contracts for firm energy that ran from January 2002 through June 2003 as well as higher prices for the unhedged portion of the natural gas that we burned in our gas-fired units. Also contributing to the increase in fuel costs were a smaller net gain from our natural gas derivative contracts (which reduces fuel expense) in the first quarter of 2004 ($3.0 million) as compared to the first quarter of 2003 ($4.6 million) and a $1 million payment in the fourth quarter of 2003, expensed as additional fuel costs in the third quarter of 2003, pursuant to a settlement with Enron of a fuel contract dispute. 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 third and fourth quarters of 2003 and the first quarter of 2004 than to purchase power. This decrease in purchased power costs also reflects the non-renewal of the short-term contracts for firm energy discussed above. The net increase in fuel and purchased power during the twelve months ended March 31, 2004 as compared to the same period last year was $5.6 million (5.1%).

Regulated – other operating expenses increased approximately $7.0 million (15.5%) during the twelve months ended March 31, 2004, compared to the same period last year due primarily to increases in employee pension expense of approximately $4.2 million (due in part to increased amortization of prior year asset losses as required by the provisions of FAS 87), employee health care expense of approximately $0.7 million and the first quarter 2004 addition to bad debt expense of $0.4 million.

Maintenance and repairs expense decreased approximately $2.8 million (12.1%) during the twelve months ended March 31, 2004, compared to the year ago period reflecting a $5.1 million decrease in maintenance costs for our gas-fired units, a $1.7 million increase in maintenance costs for our coal-fired units and a $0.6 million increase in distribution maintenance costs. The decrease in maintenance and repairs expense for our gas-fired units is primarily related to the SLCC and reflects, in part, a $1.8 million 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 as well as estimated monthly credits we have been accruing since July 2003. Monthly payments on this contract had been based on an assumption of 250 equivalent starts per unit each year. Actual equivalent starts during the twelve month period ended

June 30, 2003, however, were significantly less than originally estimated, resulting in the June 2003 true-up credit. We are now expensing maintenance costs and accruing a credit based on actual monthly usage hours for the contract year ending June 30, 2004. As of March 31, 2004, we have accrued $1.8 million in estimated credits, of which 40% belongs to Westar Generating, Inc., the owner of 40% of the SLCC. The increase in maintenance costs for our coal fired units was mainly related to maintenance outages at the Iatan and Riverton plants during the second quarter of 2003. Depreciation and amortization expense increased approximately $3.0 million (11.5%) 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 $1.0 million (6.3%) due to increased property taxes reflecting our additions to plant in service and increased city taxes in the first quarter of 2004 as compared to the first quarter of 2003 when we had a decrease in city taxes resulting from the refund of the IEC in the first quarter of 2003.

Non-regulated Items

We began investing in non-regulated businesses in 1996 and now lease capacity on our fiber optics network, provide Internet access, offer utility industry technical training, perform close-tolerance custom manufacturing (Mid-America Precision Products, LLC (MAPP)) and license customer information system software services through our wholly owned subsidiary, EDE Holdings, Inc.

During the first quarter of 2004, total non-regulated operating revenue decreased approximately $0.1 million (2.5%) while total non-regulated operating expense decreased approximately $0.2 million (3.3%) as compared to the first quarter of 2003. The decrease in both operating revenue and expense was attributed to MAPP.

Our non-regulated businesses generated a $0.3 million net loss in the first quarter of 2004 as compared to a $0.4 million net loss in the first quarter of 2003.

For the twelve-months ended March 31, 2004, total non-regulated operating revenue increased approximately $5.7 million (37.5%) while total non-regulated operating expense increased approximately $4.4 million (26.6%) compared with the same period in 2003. The significant increases in both revenues and expenses for the twelve-month-ended period were primarily due to the inclusion of a full year of MAPP operating revenues and expenses as compared to the prior year results which reflected the acquisition of MAPP in July 2002. The increase in expenses was also due to the activities of Conversant, Inc., a software company which began business in early 2002. Conversant markets Customer Watch, the Internet-based customer information system software formerly named Centurion that was developed by our employees. In June 2003, Conversant, Inc. signed a contract with Intermountain Gas Company of Boise, Idaho. A pilot project has been successfully completed and Conversant, Inc. began contributing license revenues in the fourth quarter of 2003. Full implementation is scheduled to be complete by midyear 2004.

Our non-regulated businesses generated a $1.3 million net loss for the twelve-months ended March 31, 2004 as compared to a $1.6 million net loss for the same period in 2003.

Nonoperating Items

Total allowance for funds used during construction (“AFUDC”) decreased $0.2 million for the first quarter of 2004 as compared to the first quarter of 2003 and $0.6 million during the twelve months ended March 31, 2004 as compared to the prior year due to lower levels of construction for periods ending March 31, 2004.

Total interest charges on long-term debt decreased $0.6 million (9.1%) during the first quarter of 2004 compared to the same period last year primarily reflecting the refinancing we

accomplished in 2003 by calling higher interest debt issues and replacing them with debt issues at lower interest rates. Total interest charges on long-term debt increased $0.3 million (1.1%) for the twelve months ended March 31, 2004 as compared to the same period in 2003 primarily reflecting interest on additional long-term debt as a result of our repaying short-term debt in December 2002 with the issuance of $50 million of our unsecured 7.05% Senior Notes which mature on December 15, 2022. See “ - Liquidity and Capital Resources” for further information. Commercial paper interest was virtually the same for the first quarters of 2004 and 2003 while decreasing $0.1 million for the twelve months ended March 31, 2004 as compared to the prior year period reflecting decreased usage of short-term debt as well as lower interest rates.

Other Comprehensive Income

The change in the fair value 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 included 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 they are actually realized or no longer qualify for hedge accounting. We had a net change in unrealized gain of $0.3 million for the first quarter of 2004 as compared to a net change in unrealized gain of $1.4 million for the first quarter of 2003. We had a net change in unrealized gain of $1.0 million for the twelve months ended March 31, 2004 as compared to a net change in unrealized gain of $5.4 million for the twelve months ended March 31, 2003.

We had entered into an interest rate derivative contract in May 2003 to hedge against the risk of a rise in interest rates impacting our 4.5% Senior Notes due 2013 prior to their issuance on June 17, 2003. Costs associated with the interest rate derivative (primarily due to interest rate fluctuations) amounted to approximately $2.7 million and have been capitalized as a regulatory asset and will be amortized over the life of the 2013 Notes, along with the $9.1 million redemption premium paid on the redemption of the $100 million aggregate principal amount of our 7.70% Senior Notes due 2004. The $60 million 30-year interest rate derivative contract that we had entered into on May 16, 2003 to hedge against the risk of a rise in interest rates impacting our 6.7% Senior Notes due 2033 prior to their issuance on November 3, 2003, expired on October 29, 2003 with a gain of $5.1 million. This amount was recorded as a regulatory liability and will be amortized against interest expense over the 30 year life of the debt issue we had hedged. See Note 4 – Long Term Debt under “Notes to Consolidated Financial Statements (Unaudited)”. We had no interest rate derivative contracts in 2002.

LIQUIDITY AND CAPITAL RESOURCES

Cash Provided by Operating Activities

Our net cash flows provided by operating activities increased $0.3 million during the first quarter of 2004 as compared to the first quarter of 2003, despite a $4.2 million decrease in net income, primarily due to the refunding of $18.7 million to our Missouri electric customers in the first quarter of 2003 (the amount of the IEC, with interest, collected between October 2001 and December 2002). Positively impacting cash flows provided by operating activities during the first quarter of 2004 compared to the same period in 2003 were a $2.2 million increase in customer deposits, interest

and taxes accrued, a $1.1 million increase in depreciation and amortization due to increased plant in service and a $0.8 million increase in prepaid expenses and deferred charges. Negatively impacting cash provided by operating activities were a $9.8 million decrease due to changes in accounts receivable and accrued unbilled revenues, a decrease in deferred income taxes of $1.6 million and a $7.1 million decrease due to changes in accounts payable and accrued liabilities resulting from payments for the FT8 peaking units at the Energy Center during the first quarter of 2003.

Capital Requirements and Investing Activities

Our net cash flows used in investing activities decreased $22.2 million during the first quarter of 2004 as compared to the first quarter of 2003, primarily reflecting the completion of the two FT8 peaking units at the Empire Energy Center in April 2003.

Our capital expenditures totaled approximately $8.4 million during the first quarter of 2004 compared to approximately $29.8 million for the same period in 2003. Capital expenditures, as used in this section, include AFUDC. Capital expenditures to retire assets and benefits from salvage are not included here, but are included in capital expenditures on our Consolidated Statements of Cash Flows.

A breakdown of the capital expenditures for the first quarter of 2004 is as follows:

	Quarter Ended March 31, 2004
	(in millions)
Distribution and transmission system additions	$	6.2
Additions and replacements - Asbury	0.4
Additions and replacements - Riverton, Iatan, Ozark Beach, Energy Center, State Line and State Line Combined Cycle	0.2
System mapping project	0.5
Fiber optics (non-regulated)	0.3
Other non-regulated capital expenditures	0.1
Other	0.7
Total	$	8.4

Approximately 76% of the cash requirements for capital expenditures during the first quarter of 2004 were satisfied internally from operations (funds provided by operating activities less dividends paid). We currently expect that internally generated funds will provide 100% of the funds required for the remainder of our 2004 construction 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 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 provided by financing activities decreased $18.2 million during the first quarter of 2004 as compared to the first quarter of 2003 resulting in a $13.5 million use of cash in the current year. Our net cash flows provided by financing activities were primarily affected by borrowing and repayment of short-term debt (commercial paper).

On March 1, 2001, the Empire District Electric Trust I issued two million shares of its 8 1/2% Trust Preferred Securities in a public underwritten offering. This sale generated proceeds of $50.0 million and issuance costs of $1.8 million. Holders of the trust preferred securities are entitled

to receive distributions at an annual rate of 8 1/2% of the $25 per share liquidation amount. Quarterly payments of dividends by the trust, as well as payments of principal, are made from cash received from corresponding payments made by us on $50.0 million aggregate principal amount of our 8.5% Junior Subordinated Debentures due March 1, 2031, issued by us to the trust, and held by the trust as assets. Our interest payments on the debentures are tax deductible by us. We have effectively guaranteed the payments due on the outstanding trust preferred securities. The net proceeds of this offering were added to our general funds and were used to repay short-term indebtedness. See the discussion of FIN No. 46-R under “- Recently Issued Accounting Standards” in Note 2 to the “Consolidated Financial Statements (Unaudited)” for further information.

On May 22, 2002, we sold to the public in an underwritten offering 2,500,000 shares of newly issued common stock for $51.9 million. The net proceeds of approximately $49.4 million were used to repay $37.5 million of our First Mortgage Bonds, 7.50% Series due July 1, 2002 and to repay short-term debt.

On December 23, 2002, we sold to the public in an underwritten offering $50 million of our unsecured 7.05% Senior Notes which mature on December 15, 2022. The net proceeds of approximately $48.6 million were added to our general funds and used to repay short-term debt.

On June 17, 2003 we sold to the public in an underwritten offering, $98 million of our unsecured 4.5% Senior Notes that mature on June 15, 2013 for net proceeds of approximately $96.6 million. We used the net proceeds from this issuance, along with short-term debt, to redeem all $100 million aggregate principal amount of our Senior Notes, 7.70% Series due 2004 for approximately $109.8 million, including interest. See Note 4 under Notes to Consolidated Financial Statements (Unaudited) for further details.

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, subject to the approval of the Missouri Public Service Commission to mortgage property, first mortgage bonds remain available for issuance.

On April 17, 2003, we closed a two-year renewal of our $100 million unsecured revolving credit facility which was to expire on May 12, 2003. 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 Trust Preferred Securities or the related 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 distributions on the Trust Preferred Securities) for the trailing four fiscal quarters at the end of each fiscal quarter. Failure to maintain these ratios would result in an event of default under the credit facility and would prohibit us from borrowing funds thereunder. We are in compliance with these ratios as of March 31, 2004. This credit facility is also subject to cross-default if we default in excess of $5,000,000 in the aggregate on

our other indebtedness. There were no borrowings outstanding under this revolver as of March 31, 2004. Our commercial paper borrowings decreased to zero at March 31, 2004 compared to $13 million at December 31, 2003.

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, 2004 would permit us to issue approximately $227.4 million of new first mortgage bonds based on this test with an assumed interest rate of 7.0%, subject to approval of the Missouri Public Service Commission to mortgage property.

As of March 31, 2004, the ratings for our securities were as follows:

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

Moody’s and Standard & Poor’s currently have a negative outlook and a stable outlook, respectively, 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 the cost of the securities when they 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 as described above, 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, 2004:

	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	$	—	$	348.1
Note Payable to Securitization Trust	50.0		—		—		—		50.0
Capital Lease Obligations	0.5		0.2		0.3		—		—
Operating Lease Obligations	0.7		0.6		0.1		—		—
Purchase Obligations*	228.7		44.5		63.5		49.6		71.1
Open Purchase Orders	13.3		10.3		1.2		1.2		0.6
Other Long-Term Liabilities**	3.3		0.4		1.0		1.9		—

Total Contractual Obligations	$	654.6	$	56.0	$	76.1	$	52.7	$	469.8

*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. EDE Holdings, Inc. is the 25% guarantor of a $2.4 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, 2003 for a discussion of our critical accounting policies. There were no changes in these policies in the quarter ended March 31, 2004.

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 significant financing through our issuance of commercial paper. We manage our interest rate exposure by limiting our variable-rate exposure 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 2004 than in 2003, our interest expense would increase, and income before taxes would decrease by less than $150,000. This amount has been determined by considering the impact of the hypothetical interest rates on our commercial paper balances as of December 31, 2003. At March 31, 2004, however, we have no commercial paper balance. 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 long-term contracts for the purchase of coal in order to manage our exposure to fuel prices. We satisfied 72.6% of our 2003 fuel supply need through coal. All of our anticipated 2004 supply of coal has been acquired at fixed prices (including standard adjustments). Future coal supplies will be acquired using a combination of fixed pricing and price hedging strategies. 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. As of April 16, 2004, 63% of our anticipated volume of natural gas usage for the remainder of year 2004 is hedged. See Note 3 of “Notes to Consolidated Financial Statements (Unaudited)” for further information.

If average natural gas prices should increase 10% more in 2004 than in 2003, our fuel expense would increase, and income before taxes would decrease by approximately $2 million.

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 identified in connection with the evaluation described above that occurred during the first quarter of 2004 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 22, 2004.

(b) The following persons were re-elected Directors of Empire to serve until the 2007 Annual Meeting of Stockholders:

Ross C. Hartley (19,955,131 votes for; 404,185 withheld authority).

Julio S. Leon (19,786,310 votes for; 573,006 withheld authority).

The following person was elected Director of Empire to serve until the 2007 Annual Meeting of Stockholders:

Allan T. Thoms (19,928,123 votes for; 431,193 withheld authority).

The term of office as Director of the following other Directors continued after the meeting: D. Randy Laney, Mary M. Posner, Melvin F. Chubb, Myron W. McKinney, William L. Gipson, B. Thomas Mueller and Robert L. Lamb.

Item 5. Other Information.

At March 31, 2004, our ratio of earnings to fixed charges was 2.26x. See Exhibit (12) hereto.

Item 6. Exhibits and Reports on Form 8-K.

(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.

(b) Reports on Form 8-K.

(1) In a current report dated and filed January 8, 2004, Empire filed an opinion of Anderson, Byrd, Richeson, Flaherty & Henrichs regarding the legality of Empire’s issuance and sale of 300,000 shares of common stock.

(2) In a current report dated January 29, 2004 and filed January 30, 2004, Empire filed a press release announcing the Company’s earnings for the fourth quarter of 2003 and for the twelve month period ended December 31, 2003 and the script for its earnings release conference call held on January 30, 2004.

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

May 7, 2004