EMPIRE DISTRICT ELECTRIC CO - 10-Q Quarterly Report

THE EMPIRE DISTRICT ELECTRIC COMPANY

INDEX

Part I -	Financial Information:

Item 1.	Consolidated Financial Statements (Unaudited):

	a. Consolidated Statements of Income (Loss)	3

	b. Consolidated Statement of Comprehensive Income	5

	c. Consolidated Balance Sheet	6

	d. Consolidated Statement of Cash Flows	7

	e. Notes to Consolidated Financial Statements	8

	Forward Looking Statements	10

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	11

	Results of Operations	11

	Liquidity and Capital Resources	18

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	23

Item 4.	Controls and Procedures	24

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	24

Item 5.	Other Information	25

Item 6.	Exhibits and Reports on Form 8-K	25

Signatures		26

Certifications		27

PART I. FINANCIAL INFORMATION

Item 1. Consolidated Financial Statements

EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF INCOME (LOSS) (UNAUDITED)

	Three Months Ended March 31,
	2003			2002
Operating revenues:
Electric	$	71,288,537		$	64,561,547
Water	325,688			257,895
Non-regulated	5,291,504			477,110
	76,905,729			65,296,552
Operating revenue deductions:
Operating expenses:
Fuel	8,763,492			14,280,552
Purchased power	18,536,644			14,756,176
Non-regulated	5,521,683			823,860
Other	11,239,185			10,119,562
Expenses related to terminated merger	—			1,524,355
Total operating expenses	44,061,004			41,504,505

Maintenance and repairs	4,792,883			6,085,937
Depreciation and amortization	6,814,916			6,484,303
Provision for income taxes	3,378,682			(223,722		)
Other taxes	3,672,919			3,801,058
	62,720,404			57,652,081

Operating income	14,185,325			7,644,471
Other income and deductions:
Interest income	17,616			29,116
Provision for other income taxes	25,608			12,864
Minority interest	(97,070		)	—
Other - net	(185,376		)	(221,642		)
	(239,222		)	(179,662		)
Income before interest charges	13,946,103			7,464,809
Interest charges:
Long-term debt - other	6,737,290			6,596,748
Trust preferred distributions by subsidiary holding solely parent debentures	1,062,500			1,062,500
Commercial paper	78,262			140,034
Allowance for borrowed funds used during construction	(195,589		)	(100,768		)
Other	239,375			302,839
	7,921,838			8,001,353
Net income (loss) applicable to common stock	$	6,024,265		$	(536,544	)

Weighted average number of common shares outstanding	22,607,643			19,784,887

Basic and diluted earnings (loss) per weighted average share of common stock	$	0.27		$	(0.03	)

Dividends per share of common stock	$	0.32		$	0.32

See accompanying Notes to Consolidated Financial Statements.

EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

	Twelve Months Ended March 31,
	2003			2002
Operating revenues:
Electric	$	301,298,783		$	267,456,578
Water	1,143,465			1,065,780
Non-regulated	15,069,924			1,621,208
	317,512,172			270,143,566
Operating revenue deductions:
Operating expenses:
Fuel	44,238,406			61,605,544
Purchased power	66,545,575			55,656,193
Non-regulated	16,608,844			2,131,333
Other	44,183,914			37,977,947
Expenses related to terminated merger	—			1,651,442
Total operating expenses	171,576,739			159,022,459

Maintenance and repairs	23,102,920			22,044,455
Depreciation and amortization	26,415,043			29,059,460
Provision for income taxes	16,993,202			3,681,453
Other taxes	16,047,307			13,929,020
	254,135,211			227,736,847

Operating income	63,376,961			42,406,719
Other income and deductions:
Allowance for equity funds used during construction	—			345,549
Interest income	75,835			143,723
Loss on plant disallowance	—			(4,087,066		)
Provision for other income taxes	93,542			1,548,710
Minority interest	(239,533		)	—
Other - net	(730,288		)	(1,097,477		)
	(800,444		)	(3,146,561		)
Income before interest charges	62,576,517			39,260,158
Interest charges:
Long-term debt - other	25,098,504			26,395,402
Trust preferred distributions by subsidiary holding solely parent debentures	4,250,000			4,250,000
Commercial paper	651,416			1,511,679
Allowance for borrowed funds used during construction	(665,629		)	(1,502,593		)
Other	1,157,300			946,500
	30,491,591			31,600,988
Net income applicable to common stock	$	32,084,926		$	7,659,170

Weighted average number of common shares outstanding	22,129,912			18,314,288

Basic and diluted earnings per weighted average share of common stock	$	1.45		$	0.42

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,
	2003			2002

Net income	$	6,024,265		$	(536,544	)

Derivative contracts settled	(3,898,858		)	1,365,150
Change in fair market value of open and/or derivative contracts for period	6,086,185			5,370,070
Income taxes	(831,184		)	(2,559,384		)
Net change in unrealized gain/(loss) on derivative contracts:	1,356,143			4,175,836

Comprehensive Income	$	7,380,408		$	3,639,292

	Twelve Months Ended March 31,
	2003			2002

Net income	$	32,084,926		$	7,659,170

Derivative contracts settled	(4,926,348		)	2,055,550
Change in fair market value of open and/or derivative contracts for period	13,644,225			2,129,170
Income taxes	(3,312,793		)	(1,590,194		)
Net change in unrealized gain/(loss) on derivative contracts:	5,405,083			2,594,526

Comprehensive Income	$	37,490,010		$	10,253,696

See accompanying Notes to Consolidated Financial Statements

EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEET (UNAUDITED)

	March 31, 2003		December 31, 2002
ASSETS
Utility plant, at original cost:
Electric	$	1,104,117,665	$	1,099,983,796
Water	8,481,730		8,400,720
Non-regulated	18,665,693		17,075,955
Construction work in progress	65,517,051		41,504,451
	1,196,782,139		1,166,964,922
Accumulated depreciation	379,302,793		372,892,648
	817,479,346		794,072,274
Current assets:
Cash and cash equivalents	2,882,335		14,439,227
Accounts receivable - trade, net	16,957,654		21,993,819
Accrued unbilled revenues	6,893,575		9,543,729
Accounts receivable - other	7,536,225		9,979,840
Fuel, materials and supplies	31,135,742		31,227,447
Unrealized gain in fair value of derivative contracts	8,560,267		5,983,490
Prepaid expenses	1,792,567		1,640,745
	75,758,365		94,808,297
Deferred charges:
Regulatory assets	36,276,759		36,169,683
Unamortized debt issuance costs	6,301,395		6,287,639
Unrealized gain in fair value of derivative contracts	24,353,237		16,949,388
Other	21,852,399		21,866,142
	88,783,790		81,272,852
Total Assets	$	982,021,501	$	970,153,423

CAPITALIZATION AND LIABILITIES:
Common stock, $1 par value, 22,684,051 and 22,567,179 shares issued and outstanding, respectively	$	22,684,051	$	22,567,179
Capital in excess of par value	262,665,794		260,559,197
Retained earnings (Note 2)	38,337,160		39,544,819
Accumulated other comprehensive income (net)	7,999,609		6,643,467
Total common stockholders’ equity	331,686,614		329,314,662
Long-term debt
Company obligated manditorily redeemable trust preferred securities of subsidiary holding solely parent debentures	50,000,000		50,000,000
Obligations under capital lease	422,294		462,618
First mortgage bonds and secured debt	210,807,152		210,535,477
Unsecured debt	150,284,173		150,000,000
	411,513,619		410,998,095
Current liabilities:
Accounts payable and accrued liabilities	36,922,313		37,496,190
Commercial paper	32,552,000		22,541,000
Customer deposits	4,791,303		4,644,105
Interest accrued	9,533,747		3,990,184
Taxes accrued	913,729		—
Provision for rate refund	—		18,718,679
Obligations under capital lease	197,055		194,143
Loss in fair value of derivatives	246,097		64,000
	85,156,244		87,648,301
Noncurrent liabilities and deferred credits:
Regulatory liability	11,575,185		11,840,810
Deferred income taxes	106,612,263		103,144,549
Unamortized investment tax credits	6,041,503		6,131,000
Postretirement benefits other than pensions	4,607,286		4,928,965
Unrealized loss in fair value of derivative contracts	18,838,190		10,914,668
Minority interest	903,389		806,319
Other	5,087,208		4,426,054
	153,665,024		142,192,365
Total Capitalization and Liabilities	$	982,021,501	$	970,153,423

See accompanying Notes to Consolidated Financial Statements.

EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED STATEMENT OF CASH FLOWS (UNAUDITED)

	Three Months Ended March 31,
	2003			2002
Operating activities:
Net income (loss)	$	6,024,265		$	(536,544	)
Adjustments to reconcile net income (loss) to cash flows:
Depreciation and amortization	7,612,916			7,344,948
Pension expense (income)	196,224			(895,445		)
Deferred income taxes, net	2,408,690			(112,615		)
Investment tax credit, net	(89,497		)	8,926
Issuance of common stock and stock options for incentive plans	389,195			375,883
Unrealized gain/(loss) on derivatives	(84,748		)	—
Cash flows impacted by changes in:
Accounts receivable and accrued unbilled revenues	10,527,001			2,237,638
Fuel, materials and supplies	91,706			(67,562		)
Prepaid expenses and deferred charges	(235,910		)	236,562
Accounts payable and accrued liabilities	(611,253		)	(5,524,297		)
Customer deposits, interest and taxes accrued	6,604,490			5,042,922
Other liabilities and deferred credits	(404,438		)	2,344,533
Accumulated provision-rate refunds	(18,718,679		)	5,974,586

Net cash provided by operating activities	13,709,963			16,429,535

Investing activities:
Construction expenditures	(28,288,316		)	(13,947,091		)
Non-regulated construction and other	(1,634,061		)	(1,234,454		)

Net cash used in investing activities	(29,922,377		)	(15,181,545		)

Financing activities:
Proceeds from issuance of common stock	1,834,274			880,040
Common stock issuance costs	—			(45,333		)
Net proceeds from short-term borrowings	10,011,000			500,000
Dividends	(7,231,924		)	(6,330,660		)
Long-term debt issuance costs	(143,741		)	—
Net issuance (repayment) of long-term debt	185,913			(27,022		)

Net cash provided by (used in) financing activities	4,655,522			(5,022,975		)

Net (decrease) in cash and cash equivalents	(11,556,892		)	(3,774,985		)

Cash and cash equivalents at beginning of period	14,439,227			11,440,275

Cash and cash equivalents at end of period	$	2,882,335		$	7,665,290

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, 2002.

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. In the third quarter of 2002, we began recording our non-regulated revenue in “Non-regulated” under Operating Revenues and in the fourth quarter of 2002, began recording our non-regulated expense in “Non-regulated” under the Operating Revenue Deductions section of our income statements rather than netting them under “Other - net” in the Other Income and Deductions section. In the first quarter of 2003, we began recording our gains on the ineffective (overhedged) portion of our hedging activities related to our fuel procurement program in “Fuel” under the Operating Revenue Deductions section of our income statements rather than in “Other - net” under the Other Income and Deductions section as described in the following Note 6.

Note 2 - Retained Earnings

	First Quarter 2003

Balance at January 1, 2003	$	39,544,819
Changes January 1 through March 31:
Net income	6,024,265
Quarterly cash dividends on common stock: - $0.32 per share	(7,231,924		)

Total changes January 1 through March 31	(1,207,659		)

Balance at March 31, 2003	$	38,337,160

Note 3 - Non-regulated Businesses

On February 1, 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.

The table below presents information about the reported revenues, operating income, net income, construction expenditures, total assets and minority interests of our non-regulated businesses, including MAPP and Fast Freedom, Inc.

	As and for the quarter ended March 31,
	2003					2002
	Non-Regulated			Total Company		Non-Regulated			Total Company
Statement of Income Information
Revenues	$	5,342,701	*	$	76,905,729	$	477,110		$	65,296,552
Operating income (loss)	$	(312,000	)	$	14,185,325	$	(330,556	)	$	7,644,471
Net income (loss)	$	(409,375	)	$	6,024,265	$	(330,556	)	$	(536,544	)
Minority interest	$	97,070		$	97,070	$	—		$	—

Balance Sheet Information
Construction expenditures	$	824,546		$	28,293,459	$	925,653		$	14,664,683
Total assets	$	23,432,915		$	982,021,501	$	12,618,385		$	889,264,758
Minority interest	$	903,389		$	903,389	$	—		$	—

*Includes fiber optics revenues received from the regulated business that are eliminated in consolidations.

Note 4 - Adoption of Accounting Standard

In June 2001, the Financial Accounting Standards Board issued SFAS No. 143, “Accounting for Obligations Associated with the Retirement of Long-Lived Assets” (FAS 143). This statement establishes standards for accounting and reporting for legal and constructive obligations associated with the retirement of tangible long-lived assets. We adopted FAS 143 on January 1, 2003 and have identified future asset retirement obligations associated with the removal of certain river water intake structures and equipment at the Iatan Power Plant in which we have a 12% ownership. We also have a liability for future containment of an ash landfill at the Riverton Power Plant.

The potential costs of these future liabilities are based on engineering estimates of third party costs to remove the assets in satisfaction of the associated obligations. These liabilities have been estimated as of the settlement date and have been discounted using a credit adjusted risk free rate ranging from 5.0% to 5.52% depending on the settlement date. Revisions to these liabilities could occur due to changes in the cost estimates, anticipated timing of settlement or federal or state regulatory requirements. Upon adoption of this statement, we recorded a non-recurring discounted liability of approximately $630,000 in the first quarter of 2003. There was no material effect to the Consolidated Statement of Income. This liability will be accreted over the period up to the estimated settlement date.

Note 5 - Risk Management and Derivative Financial Instruments

On January 1, 2001, we adopted the provisions of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (FAS 133) and SFAS No. 138, “Accounting for Certain Derivative Instruments and Certain Hedging Activities and Amendment of SFAS 133” (FAS 138). FAS 133, as amended, requires recognition of all derivatives as either assets or liabilities on the balance sheet measured at fair value. 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.

FAS 133 requires all derivatives to be recognized on the balance sheet at their fair value. On the date a derivative contract is entered into, the derivative is designated as (1) a hedge of a forecasted transaction or of the variability of cash flows to be received or paid related to a recognized asset or liability (“cash-flow” hedge); or (2) an instrument that is held for non-hedging purposes (a “non-hedging” instrument). Changes in the fair value of a derivative that is highly effective and designated and qualifies as a cash-flow hedge are recorded in other comprehensive income, until earnings are affected by the variability of cash flows (e.g., when periodic settlements on a variable-rate asset or liability are recorded in earnings). Changes in the fair value of non-hedged derivative instruments are reported in current-period earnings.

We discontinue hedge accounting prospectively when (1) it is determined that the derivative is no longer effective in offsetting changes in cash flows of a hedged item (including forecasted transactions); (2) the derivative expires or is sold, terminated, or exercised; (3) the derivative is designated as a non-hedging instrument, because it is unlikely that a forecasted transaction will occur; or (4) management determines that designation of the derivative as a hedge instrument is no longer appropriate.

As of March 31, 2003, we have recorded the following assets and liabilities representing the fair value of qualifying derivative financial instruments held as of that date and subject to the reporting requirements of FAS 133.

Current assets	$	8,560,267	Current liabilities	$	246,097

Noncurrent assets	$	24,353,237	Noncurrent liabilities	$	18,838,190

A $7,999,609 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 $4,902,987 on this gain is included in deferred taxes. These amounts are adjusted cumulatively on a monthly basis during the determination periods beginning April 1, 2003 and ending on December 31, 2004. At the end of each determination period any gain or loss for that period related to the instrument will be reclassified to fuel expense.

In the first quarter of 2003, we began recording unrealized gains on the ineffective (overhedged) portion of our hedging activities in “Fuel” under the Operating Revenues Deductions section of our income statements as allowed by FAS 133 since all of our hedging activities are related to stabilizing fuel costs as part of our fuel procurement program and are not speculative ventures. We had previously recorded such gains, which were not material in the prior periods ending March 31, 2002, in “Other - net” under the Other Income and Deductions section. Gains from the ineffective (overhedged) portion of our hedging activities included in “Fuel” were $1.7 million (pre-tax) for the quarter ended March 31, 2003 and $2.9 million (pre-tax) for the twelve months ended March 31, 2003.

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, 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 receive 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; weather, business and economic conditions; 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 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 effect 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.

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

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, 2003, compared to the same periods ended March 31, 2002.

Operating Revenues and Kilowatt-Hour Sales

Of our total electric operating revenues during the first quarter of 2003, approximately 45% were from residential customers, 27% from commercial customers, 15% from industrial customers, 4% from wholesale on-system customers, 5% from wholesale off-system transactions and 4% from miscellaneous sources such as transmission services and late payment fees. The percentage changes from the prior year in kilowatt-hour (“Kwh”) sales and revenue by major customer class were as follows:

	Kwh Sales				Revenue
	First Quarter		Twelve Months Ended		*First Quarter		*Twelve Months Ended
Residential	6.1	%	6.0	%	13.3	%	11.2	%
Commercial	2.9		1.3		9.7		6.2
Industrial	5.1		3.9		13.0		8.9
Wholesale On-System	1.1		1.9		(5.9	)	(7.2	)
Total On-System	4.6		3.7		11.2		12.6

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

On-System Transactions

Kwh sales for our on-system customers increased 4.6% during the first quarter of 2003 over the first quarter of 2002 primarily due to colder temperatures during 2003 as compared to milder temperatures during 2002. Total heating degree days (the number of degrees that the average temperature for that period was below 65° F) for the first quarter of 2003 were 15.5% more than the 20-year average and 8.0% more than the same period last year. A new all-time winter peak of 987 megawatts was established on January 23, 2003 replacing the previous winter peak of 941 megawatts established in December 2000. Revenues for our on-system customers increased $6.7 million (11.2%) primarily as a result of the increased sales and the Missouri and Kansas rate increases discussed below. The December 2002 Missouri rate increase accounted for approximately $2.8 million and the July 2002 Kansas rate increase contributed approximately $0.6 million of this increase.

The increases in residential and commercial Kwh sales during the first quarter of 2003 were primarily due to these weather conditions. Residential and commercial revenues were also positively affected by the December 2002 Missouri rate increase and, to a lesser extent, the July 2002 Kansas rate increase.

Industrial Kwh sales, although not particularly weather sensitive, also increased for the first quarter of 2003 reflecting increased sales because of better economic conditions as compared to the first quarter of 2002 when our service territory experienced a general slowdown in economic activity. Industrial revenues increased, reflecting the increased sales, the December 2002 Missouri rate increase and the July 2002 Kansas rate increase.

On-system wholesale Kwh sales increased during the first quarter of 2003 reflecting the weather conditions described above. Revenues associated with these FERC regulated sales decreased as a result of lower fuel costs recovered through the operation of the fuel adjustment clause.

For the twelve months ended March 31, 2003, residential and commercial Kwh sales and revenues increased, primarily due to cooler temperatures in April 2002, the fourth quarter of 2002 and the first quarter of 2003 (during our heating seasons) and warmer temperatures in June and September of 2002 (during our air conditioning season) as compared to the prior year periods. Residential and commercial revenues were also positively affected by the October 2001 Missouri rate increase, the December 2002 Missouri rate increase and the July 2002 Kansas rate increase. Industrial sales increased during the twelve-month period, primarily reflecting the improved economic conditions. Industrial revenues increased due to the increased sales, the 2001 Missouri rate increase and the 2002 Missouri and Kansas rate increases. On-system wholesale Kwh sales increased for the twelve months ended March 31, 2003 reflecting the weather conditions discussed above while associated revenues decreased reflecting 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

On September 20, 2001, the Missouri Commission granted us an annual increase in rates for our Missouri electric customers of approximately $17.1 million, or 8.4%, effective October 2, 2001. In addition, the 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).

On March 8, 2002, we filed a request with the Missouri Commission for an annual increase in base rates for our Missouri electric customers in the amount of $19,779,916 and also asked to have the IEC reconfigured to reflect a decrease of $9,994,888 in the amount to be billed to customers. On June 4, 2002, a Unanimous Stipulation and Agreement was approved by the Missouri Commission which provided for a $7 million annual reduction in the IEC.

On November 22, 2002, another Unanimous Stipulation and Agreement was approved by the Missouri Commission which provided us with an annual increase in rates for our Missouri electric customers of approximately $11.0 million, or 4.97%, effective December 1, 2002 and eliminated the IEC as of that date. The Agreement also called for us to refund all funds collected under the IEC, with interest, by March 15, 2003. The Agreement also provided for a change to the summer/winter rate differential for our residential customers with the new rates reflecting a smaller differential between summer and winter rates for usage above 600 kilowatt hours. Each of the parties to the Agreement also agreed not to file a new request for a general rate increase or decrease before September 1, 2003, barring any unforeseen, extraordinary occurrences.

At December 31, 2002, we had recorded a current liability of approximately $18.7 million for such rate refunds. We collected $2.8 million in 2001 and recorded $0.75 million as revenue. We collected $15.9 million in 2002 and recorded a revenue reduction of ($0.75) million associated with the revenue recognized in 2001 because it became certain that the entire amount of IEC revenues collected would be refunded. As a result, we recognized no revenue in the aggregate in 2001 and 2002 associated with the IEC collections. The remainder of the funds collected in 2001 and 2002 were set aside as a provision for rate refunds and not recognized in operating revenue. As a result of the non-recognition of these funds, the refunds did not have a material impact on our earnings for the first quarter of 2003 when they were refunded to our customers.

On December 23, 2002, an annual increase in rates for our Missouri water customers of approximately $358,000, or 33.7% became effective.

On June 27, 2002, a Unanimous Stipulation and Agreement was approved by the Kansas Corporation Commission providing an annual increase in rates for our Kansas customers of approximately $2,539,000, or 17.87%, effective July 1, 2002. The agreement also provides that we

will not file for general rate relief before November 1, 2003 barring any unforeseen, extraordinary occurrences.

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%. We expect a decision from the Oklahoma Commission by September 2003.

On March 17, 2003, we filed a request with the Federal Energy Regulatory Commission (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.

Off-System 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. During the first quarter of 2003, revenues from such off-system transactions were approximately $4.1 million as compared to approximately $4.0 million in the first quarter of 2002. For the twelve months ended March 31, 2003, revenues from such off-system transactions were approximately $25.5 million as compared to $9.5 million for the twelve months ended March 31, 2002. The increase in revenues for the twelve months ended March 31, 2003 resulted primarily from the availability of competitively priced power from our SLCC which was placed in service in June 2001 and term purchases of firm energy during 2002 and the first quarter of 2003 which, when not required to meet our own customers’ needs, could be sold in the wholesale market.

We, and all other electric utilities with interstate transmission facilities, operate under FERC regulated open access tariffs that provide all wholesale buyers and sellers of electricity the opportunity to procure transmission services (at the same rates) that the utilities provide themselves. We are a member of the Southwest Power Pool (SPP), a regional reliability coordinator of the North American Electric Reliability Council. Effective September 1, 2002, we began taking Network Integration Transmission Service under the SPP’s Open Access Transmission Tariff. This provides a cost-effective way for us to participate in a broader market of generation resources with the possibility of lower transmission costs. This tariff provides for a zonal rate structure, whereby transmission customers pay a pro-rata share, in the form of a reservation charge, for the use of the facilities for each transmission owner that serves them. Currently, all revenues collected within a zone are allocated back to the transmission owner serving the zone. Since we are a transmission provider for our zone and are currently the only transmission customer taking service from that zone, we are currently being assessed 100 per cent of the zonal costs and receiving it back (less a small service charge) as revenue. To the extent that we are allocated these revenues and charges to serve our on-system wholesale and retail power customers, the associated costs are netted against the revenues collected and only the difference, if any, is recorded. In the event that other transmission customers take Network Integration Transmission Service in our zone, the revenues received will be reflected in electric operating revenues and the related charges will be expensed.

In December 1999, the FERC issued Order No. 2000 which encourages the development of regional transmission organizations (RTOs). RTOs are designed to control the wholesale transmission services of the utilities in their regions thereby facilitating open and more competitive markets in bulk power. The SPP and Midwest Independent Transmission System Operator, Inc. (MISO) agreed in October 2001 to consolidate and form an RTO which was approved by the FERC in December 2001. However, on March 20, 2003, the SPP and MISO announced they had mutually agreed to terminate the consolidation of the organizations. Since the consolidation did not occur, as part of our efforts to comply with Order No. 2000, we will assess other alternatives as they become feasible. We are unable to quantify the potential impact of either joining or not joining an RTO on

our future financial position, results of operation or cash flows. Reference is made to our Annual Report on Form 10-K for the year ended December 31, 2002 under Item 1, “Business - Electric Generating Facilities and Capacity” and Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Competition” for further information.

Non-regulated Items

During the first quarter of 2003, total non-regulated operating revenue increased approximately $4.8 million while total non-regulated operating expense increased approximately $4.7 million compared with 2002. For the twelve-months ended March 2003, total non-regulated operating revenue increased approximately $13.4 million while total non-regulated operating expense increased approximately $14.5 million. The increase in both revenues and expenses for both periods presented was primarily due to the consolidation of the financial statements of Mid-America Precision Products, LLC (MAPP), which we acquired in July 2002. The increase in expense for the twelve months ended March 31, 2003 was also due to the activities of our wholly owned subsidiary, Conversant, Inc., a software company that began business in early 2002. We began investing in non-regulated businesses in 1996 and now lease capacity on our fiber optics network and provide Internet access, utility industry technical training, close-tolerance custom manufacturing and other energy services through our wholly owned subsidiary, EDE Holdings, Inc.

Our non-regulated businesses generated a $0.4 million net loss in the first quarter of 2003 as compared to a $0.3 million net loss in the first quarter of 2002 and a net loss of $1.6 million for the twelve months ended March 31, 2003 as compared to a net loss of $0.7 million for the twelve months ended March 31, 2002.

Operating Revenue Deductions

During the first quarter of 2003, total operating expenses increased approximately $2.6 million (6.2%) compared with the same period last year. Purchased power costs increased approximately $3.8 million (25.6%) but were offset by a $5.5 million (38.6%) decrease in fuel costs during the first quarter of 2003. The increase in purchased power costs was primarily due to increased demand resulting from colder temperatures in the first quarter of 2003, higher purchased power costs in 2003 as compared to the first quarter of 2002 and our inability at times during the extreme cold weather to get natural gas delivered. It was also more economical at times to purchase power than to utilize our own generation. Total fuel costs decreased during the first quarter of 2003 primarily due to $4.6 million of net gains recognized in relation to (1) the expiration of derivative contracts occurring during the normal course of business in the first quarter of 2003 related to the settlement of derivative contracts for natural gas ($2.6 million), (2) the disqualification of hedges for anticipated natural gas usage that was financially hedged but no longer necessary because of term purchases of firm energy during the quarter ($1.7 million) and (3) the unwinding of a physical forward contract at the counterparty’s request. In the first quarter of 2003, we began recording unrealized gains on the disqualified (overhedged) portion of our hedging activities in “Fuel” under the Operating Revenue Deductions section of our income statements. See Note 5 – Risk Management and Derivative Financial Instruments under Notes to Consolidated Financial Statements (Unaudited).

Other operating expenses increased approximately $1.1 million (11.1%) during the period due mainly to increased pension and health care expenses. We expect pension expense to approximate $0.8 million in 2003 due to a decline in the value of invested funds. Additionally, we expect to be required under ERISA to fund approximately $400,000 for the 2003 plan year. Absent a substantial recovery in the equity markets, pension expense and cash funding requirements would

substantially increase over the next several years. There were no expenses in the first quarter of 2003 relating to the terminated merger with Aquila, Inc., formerly UtiliCorp United Inc. (which was terminated by Aquila on January 2, 2001) as compared to $1.5 million during the first quarter of 2002. Expenses in the first quarter of 2002 that were related to the terminated merger were primarily the result of severance benefits incurred under our Change in Control Severance Pay Plan.

Maintenance and repairs expense decreased approximately $1.3 million (21.3%) as compared to the same period last year primarily due to lower payments during 2003 on our long-term operating plant maintenance contracts as compared to 2002 when we were making additional payments on the Energy Center and State Line Unit No. 1 contract for outage services. Lower maintenance costs at the Iatan Plant during the first quarter of 2003 (as compared to 2002 when there was a 10-week boiler overhaul outage) also contributed to the decrease. We expect maintenance and repairs expense to increase in the second quarter of 2003 due to substantial damage that occurred in the Kansas and Missouri areas of our service territory on May 4, 2003 resulting from tornadoes that initially disrupted power to an estimated 30,000 customers. The cost of property damage and reconstruction expense is preliminarily estimated at around $5 million. However, the exact cost, the extent of insurance reimbursement and the determination of how much of the cost will be capitalized as construction expenditures are not yet known. Depreciation and amortization expenses increased approximately $0.3 million (5.1%) during the quarter due to increased levels of plant and equipment. The provision for income taxes increased approximately $3.6 million during the first quarter of 2003 due to increased income. Other taxes decreased approximately $0.1 million (3.4%) during the first quarter of 2003 due to 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, 2003, total operating expenses increased approximately $12.6 million (7.9%) compared to the year ago period. Total purchased power costs increased approximately $10.9 million (19.6%) during the twelve months ended March 31, 2003 but were offset by a $17.4 million (28.2%) decrease in fuel costs during the same period. The increase in purchased power costs was primarily due to increased demand because of weather conditions in the first quarter of 2003 and the second and third quarters of 2002 and the term purchases of firm energy previously discussed. Total fuel costs decreased during the twelve months ended March 31, 2003 primarily reflecting our hedging efforts, a $1.2 million reduction to fuel expense resulting from an unrealized gain on ineffective hedges in December 2002, lower natural gas prices in 2002 as compared to the same periods in 2001 and less generation by our gas-fired units due in large part to the term purchases of firm energy.

Other operating expenses increased approximately $6.2 million (16.3%) during the twelve months ended March 31, 2003, compared to the same period last year due primarily to increases in administrative and general expense resulting from increased expense for employee health care and benefit plans as well as increased pension expense and increased transmission expense for the delivery of purchased energy to our system. There were no expenses during the twelve months ended March 31, 2003 relating to the terminated merger with Aquila, Inc. as compared to $1.7 million during the same period last year.

Maintenance and repairs expenses increased approximately $1.1 million (4.8%) during the twelve months ended March 31, 2003, compared to the year ago period. This increase was primarily due to expenditures for maintenance contracts entered into in July 2001 for the SLCC, the Energy Center and State Line Unit No. 1 that serve to levelize maintenance costs over time. Payments on the Energy Center and State Line Unit No. 1 contracts began in January 2002. Depreciation and amortization expense decreased approximately $2.6 million (9.1%) due to lower depreciation rates put into effect during the fourth quarter of 2001 as a result of the October Missouri rate order. Provision for income taxes increased $13.3 million reflecting increased income during the current

period while other taxes increased approximately $2.1 million (15.2%) due to a reduction in capitalized property taxes related to the SLCC being placed into service in June 2001.

Nonoperating Items

Total allowance for funds used during construction (“AFUDC”) was virtually the same for the first quarters of 2003 and 2002 but decreased $1.2 million (64.0%) during the twelve months ended March 31, 2003 reflecting the completion of the SLCC in June 2001.

A one-time write-down of $4.1 million was taken in the third quarter of 2001 for disallowed capital costs related to the construction of the SLCC. The net effect on earnings for the twelve months ended March 31, 2002 after considering the tax effect on this write-down was $2.5 million.

Total interest charges on long-term debt increased $0.1 million (2.1%) during the first quarter of 2003 compared to the same period last year while decreasing $1.3 million (4.9%) for the twelve months ended March 31, 2003 when compared to the corresponding period last year reflecting the maturity of $37.5 million of our first mortgage bonds in July 2002. Commercial paper interest decreased $0.1 million (44.1%) during the first quarter of 2003 as compared to the first quarter of 2002 and $0.9 million (56.9%) for the twelve months ended March 31, 2003 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 market value of open contracts related to our gas procurement program and the amount of the contracts settled during the period 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 in Accumulated Other Comprehensive Income in the capitalization section of our balance sheet and does not affect earnings per share. The unrealized gains and losses accumulated in comprehensive income are reclassified to fuel expense in the periods in which they are actually realized or no longer qualify for hedge accounting. We had a net increase in unrealized gain of $1.4 million for the first quarter of 2003 as compared to a net increase of $4.2 million for the first quarter of 2002 and a net increase in unrealized gain of $5.4 million for the twelve months ended March 31, 2003 as compared to a net increase of $2.6 million for the twelve months ended March 31, 2002.

Earnings

Basic and diluted earnings per weighted average share of common stock were $0.27 during the first quarter of 2003 as compared to a loss per share of common stock of $(0.03) during the first quarter of 2002. This increase in earnings per share was primarily due to the October 2001 and December 2002 Missouri rate increases, the July 2002 Kansas rate increase and colder temperatures during the first quarter of 2003. Also favorably impacting 2003 first quarter earnings was a $1.7 million net decrease in total fuel and purchased power costs and decreased maintenance costs. Negatively impacting earnings for the first quarter of 2002 were merger costs of $1.0 million, or $0.05 per share, net of tax, relating to the proposed merger with Aquila which was terminated on January 2, 2002. Excluding the merger expenses in the first quarter of 2002, earnings per share for the first quarter of 2002 would have been $0.02. Earnings for the second quarter of 2003 will be negatively impacted by increased maintenance and repairs expense related to the tornado damage that occurred in our service territory on May 4, 2003. Although the cost of property damage and reconstruction expense is preliminarily estimated at around $5 million, the exact cost, the extent of insurance reimbursement and the determination of how much of the cost will be capitalized as

construction expenditures are not yet known. As a result, the impact on our future earnings is difficult to estimate. The impact on our second quarter earnings per share could be material. We currently do not expect that the impact on our 2003 results will be material.

Basic and diluted earnings per weighted average share of common stock for the twelve months ended March 31, 2003, were $1.45 compared to $0.42 for the twelve months ended a year earlier. The increase was primarily due to the Missouri and Kansas rate increases, favorable weather during much of the period, a significant increase in off-system sales, a $6.5 million net decrease in total fuel and purchased power costs, and a decrease in depreciation expense. Negatively impacting earnings for the twelve months ended March 31, 2002 were $1.1 million in merger costs net of related income taxes, or $0.06 per share and a one-time non-cash charge of $2.5 million, net of related income taxes, or $0.14 per share in the third quarter of 2001 for disallowed capital costs related to the construction of the State Line Combined Cycle Unit. Excluding merger costs and the one-time non-cash charge, earnings per share for the twelve-months ended March 31, 2002 would have been $0.62.

LIQUIDITY AND CAPITAL RESOURCES

Our construction-related expenditures totaled $28.3 million during the first quarter of 2003, compared to $14.7 million for the same period in 2002. Approximately $6.9 million of these 2003 expenditures related to additions to our distribution and transmission systems, approximately $19.6 million related to the Energy Center FT8 peaking units discussed below and approximately $0.8 million related to our investment in fiber optics cable and equipment. During the first quarter of 2003, approximately 21.6% of construction expenditures were satisfied internally from operations. The remainder was satisfied from short-term borrowings and proceeds from our sales of common stock and unsecured Senior Notes discussed below.

We estimate that our construction expenditures (including AFUDC) will total approximately $50.2 million in 2003, including approximately $13.8 million for additions to our distribution system and approximately $22.0 million for the two 50 megawatt FT8 peaking units at the Empire Energy Center which began commercial operations in April 2003. We spent approximately $3.4 million in 2001, approximately $31.7 million in 2002 and approximately $19.6 million in the first quarter of 2003 on these units (including AFUDC).

Our net cash flows provided by operating activities decreased $2.7 million during the first quarter of 2003 as compared to the first quarter of 2002 primarily due to our refunding $18.7 million to our Missouri electric customers, the amount of the IEC (with interest) collected between October 2001 and December 2002. This outflow of cash was partially offset by a $6.6 million increase in net income and an $8.3 million increase due to changes in accounts receivable and accrued unbilled revenues during the first quarter of 2003.

Our net cash flows used in investing activities increased $14.8 million during the first quarter of 2003 as compared the same period in 2002 because of increased construction expenditures due to the purchase and installation of the two FT8 peaking units at the Empire Energy Center.

Our net cash flows provided by financing activities increased $9.7 million during the first quarter of 2003 as compared to 2002 due to a $9.5 million increase in short-term debt and a $1.0 million increase in proceeds from issuance of common stock offset by a $0.9 million increase in dividends.

We currently expect that internally generated funds will provide 100% of the funds required for the remainder of our 2003 construction expenditures. If necessary, we may utilize short-term debt to finance additional amounts needed for such construction and repay such borrowings with internally generated funds 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).

On December 10, 2001, we sold to the public in an underwritten offering 2,012,500 newly issued shares of our common stock for $41.0 million. The net proceeds of approximately $39.0 million from the sale were added to our general funds and used to repay short-term debt.

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.

We have an effective shelf registration under which approximately $100 million of common stock and unsecured debt securities remain available for issuance.

On December 24, 2002, we received approval from the Kansas Corporation Commission for the issuance of an additional 100,000 shares of our common stock for our Director’s Stock Unit Plan and an additional 200,000 shares of our common stock for our 401(k) Plan and ESOP.

On April 17, 2003, we closed a two-year renewal of our $100,000,000 unsecured revolving credit facility which was to expire on May 12, 2003. The 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) 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 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. This credit facility is also subject to cross-default with our other indebtedness (in excess of $5,000,000 in the aggregate). There were no borrowings outstanding under this revolver as of March 31, 2003. However, $33 million of the facility as of that date was used to back up our commercial paper and was not available to be borrowed.

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, 2003 would permit us to issue approximately $263.1 million of new first mortgage bonds based on this test with an assumed interest rate of 7.0%. The Mortgage provides an exception from this earnings requirement in certain instances, relating to the issuance of new first mortgage bonds against first mortgage bonds which have been, or are to be, retired.

Moody’s Investors Service currently rates our first mortgage bonds (other than the pollution control bonds) Baa1 and our senior unsecured debt Baa2. Standard & Poor’s downgraded our first mortgage bonds (other than the pollution control bonds) on July 2, 2002 from A- to BBB, our senior unsecured debt from BBB+ to BBB- and our Trust Preferred Securities from BBB to BB+. Standard & Poor’s outlook, however, was revised from negative to stable. In July 2001, Moody’s adjusted the credit rating of our Trust Preferred Securities from Baa1 to Baa3 due to technical changes in Moody’s methodology for rating this classification of security.

As of March 31, 2003, 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+

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 (which is Baa3 or above for Moody’s and BBB- or above for Standard & Poor’s) may also impair our ability to issue short-term debt 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, 2003:

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)	$	358.5	$	—	$	110.0	$	—	$	248.5
Trust Preferred Securities	50.0		—		—		—		50.0
Capital Lease Obligations	0.6		0.2		0.4		—		—
Operating Lease Obligations	1.3		0.6		0.7		—		—
Purchase Obligations*	273.0		45.8		76.4		51.2		99.6
Other Long-Term Liabilities**	3.3		0.3		—		3.0		—

Total Contractual Obligations	$	686.7	$	46.9	$	187.5	$	54.2	$	398.1

*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 50.01% guarantor of a $2.6 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

Set forth below are certain accounting policies that are considered by management to be critical and to possibly involve significant risk, which means that they typically require difficult, subjective or complex judgments, often as a result of the need to make estimates about the effect of matters that are inherently uncertain (other accounting policies may also require assumptions that could cause actual results to be different than anticipated results). A change in assumptions or judgments applied in determining the following matters, among others, could have a material impact on future financial results.

Pensions. Our pension expense or benefit includes amortization of previously unrecognized net gains or losses. The amortized amount represents the average of gains and losses over the prior five years, with this amount being amortized over five years. Our policy is consistent with the provisions of SFAS 87, “Employers’ Accounting for Pensions.”

Risks and uncertainties affecting the application of this accounting policy include: future rate of return on plan assets, interest rates used in valuing benefit obligations and discount rates. We expect pension expense to approximate $0.8 million in 2003 due to a decline in the value of invested funds. Additionally, we expect to be required under ERISA to fund approximately $400,000 for the 2003 plan year. Absent a substantial recovery in the equity markets, pension expense and cash funding requirements would substantially increase over the next several years.

Postretirement Benefits. We recognize expense related to postretirement benefits as earned during the employee’s period of service. Related assets and liabilities are established based upon the funded status of the plan compared to the accumulated benefit obligation. Our policy is consistent with the provisions of SFAS 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions.”

Risks and uncertainties affecting the application of this accounting policy include: future rate of return on plan assets, interest rates used in valuing benefit obligations, healthcare cost trend rates and discount rates.

Hedging Activities. We currently engage in hedging activities in an effort to minimize our risk from volatile natural gas prices. We enter into contracts with counterparties relating to our future natural gas requirements (under a set of predetermined percentages) that lock in prices in an attempt to lessen the volatility in our fuel expense and gain predictability. We recognize that if risk is not timely and adequately balanced or if counterparties fail to perform contractual obligations, actual results could differ materially from intended results. All derivative instruments are recognized on the balance sheet with gains and losses from effective instruments deferred in other comprehensive income (in stockholders’ equity), while gains and losses from ineffective (overhedged) instruments are recognized as the fair value of the derivative instrument changes. Our policy is consistent with the provisions of SFAS 138, “Accounting for Certain Derivative Instruments and Certain Hedging Activities, An Amendment of SFAS 133.”

As of April 28, 2003, 79% of our anticipated volume of natural gas usage for the remainder of year 2003 is hedged at an average price of $3.15 per Dekatherm (Dth). In addition, approximately 60% of our anticipated volume of natural gas usage for the year 2004 is hedged at an average price of $3.25 per Dth, approximately 28% of our anticipated volume of natural gas usage for the year 2005 is hedged at an average price of $4.05 per Dth and approximately 11% of our anticipated volume of natural gas usage for the year 2006 is hedged at an average price of $4.19 per Dth.

Risks and uncertainties affecting the application of this accounting policy include: market conditions in the energy industry, especially the effects of price volatility on contractual commodity commitments, regulatory and political environments and requirements, fair value estimations on longer term contracts, estimating underlying fuel demand and counterparty ability to perform.

Regulatory Assets. In accordance with SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation”, our financial statements reflect ratemaking policies prescribed by the regulatory commissions having jurisdiction over us (FERC and four states).

Certain expenses and credits, normally recognized as incurred, are deferred as assets and liabilities on the balance sheet until the time they are recovered from or refunded to customers. This is consistent with the provisions of SFAS No. 71. We have recorded certain regulatory assets which are expected to result in future revenues as these costs are recovered through the ratemaking process. Historically, all costs of this nature which are determined by our regulators to have been prudently incurred have been recoverable through rates in the course of normal ratemaking procedures, and we believe that the regulatory assets and liabilities we have recorded will be afforded similar treatment.

Unbilled Revenue. At the end of each period we estimate, based on expected usage, the amount of revenue to record for energy that has been provided to customers but not billed. Risks and uncertainties affecting the application of this accounting policy include: projecting customer energy usage and estimating the impact of weather and other factors that affect usage (such as line losses) for the unbilled period.

RECENTLY ISSUED ACCOUNTING STANDARDS

In June 2001, the Financial Accounting Standards Board (FASB) issued SFAS No. 143, “Accounting for Obligations Associated with the Retirement of Long-Lived Assets” (FAS 143). This statement establishes standards for accounting and reporting for legal and constructive obligations associated with the retirement of tangible long-lived assets. We adopted FAS 143 on January 1, 2003 and have identified future asset retirement obligations associated with the removal of certain river water intake structures and equipment at the Iatan Power Plant in which we have a 12% ownership. We also have a liability for future containment of an ash landfill at the Riverton Power Plant.

The potential costs of these future liabilities are based on engineering estimates of third party costs to remove the assets in satisfaction of the associated obligations. These liabilities have been estimated as of the settlement date and have been discounted using a credit adjusted risk free rate ranging from 5.0% to 5.52% depending on the settlement date. Revisions to these liabilities could occur due to changes in the cost estimates, anticipated timing of settlement or federal or state regulatory requirements. Upon adoption of this statement, we recorded a non-recurring discounted liability and a regulatory asset of approximately $630,000 in the first quarter of 2003. There was no material effect to the Consolidated Statement of Income. This liability will be accreted over the period up to the estimated settlement date.

In June 2002, the FASB issued SFAS No. 146 “Accounting for Costs Associated with Exit or Disposal Activities” (FAS 146). FAS 146 addresses significant issues regarding the recognition, measurement, and reporting of costs that are associated with exit and disposal activities, including restructuring activities that are currently accounted for pursuant to the guidance that the Emerging Issues Task Force has set forth. The scope of FAS 146 also includes costs related to terminating a contract that is not a capital lease and termination benefits that employees who are involuntarily terminated receive under the terms of a one-time benefit arrangement that is not an ongoing benefit arrangement or an individual deferred-compensation contract. FAS 146 is effective for exit or disposal activities that are initiated after December 31, 2002. The adoption of this Statement did not have a material impact on our financial condition and results of operations.

In December 2002, the FASB issued SFAS No. 148 “Accounting for Stock-Based Compensation-Transition and Disclosure” (FAS 148). FAS 148 amends SFAS No. 123, “Accounting for Stock-Based Compensation” (FAS 123), to provide alternative methods of transition when an entity changes from the intrinsic value method to the fair-value method of accounting for stock-based employee compensation. FAS 148 amends the disclosure requirements of FAS 123 to require more prominent and more frequent disclosure about the effects of stock-based compensation by requiring pro forma data to be presented more prominently and in a more user-friendly format in the footnotes to the financial statements. In addition, FAS 148 requires that the information be included in interim as well as annual financial statements. The transition guidance and annual disclosure provisions of FAS 148 are effective for fiscal years ending after December 15, 2002. We have adopted the transition and disclosure provisions of FAS 148 and now recognize compensation expense related to stock option issuances on or subsequent to January 1, 2002 under the fair- value provisions of FAS 123. Any stock compensation expense in prior periods has not been material. We

do not have any transition issues and, accordingly, FAS 148 did not have a material impact on our financial condition and results of operations.

In April 2003, the FASB issued SFAS No. 149 (FAS 149), “Amendment of Statement 133 on Derivative Instruments and Hedging Activities” (FAS149). FAS 149 amends and clarifies the accounting guidance on (1) derivative instruments (including certain derivative instruments embedded in other contracts) and (2) hedging activities that fall within the scope of FASB Statement No. 133 (FAS 133), Accounting for Derivative Instruments and Hedging Activities. FAS 149 is effective (1) for contracts entered into or modified after June 30, 2003, with certain exceptions, and (2) for hedging relationships designated after June 30, 2003. We are continuing to evaluate the effects of FAS 149, but do not believe its adoption will not have a material impact on our financial condition and results of operation.

In November 2002, the FASB issued FASB Interpretation No. 45 (FIN 45), “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others, and Interpretation of FASB Statements Nos. 5, 57, and 107 and recession of FASB Interpretation No. 34”. FIN 45 requires: (1) the guarantor of debt to recognize a liability, at the inception of the guarantee, for the fair value of the obligation undertaken in issuing this guarantee, (2) indirect guarantees of debt to be recognized in the financial statements of the guarantor and (3) the guarantor to disclose the background and nature of the guarantee, the maximum potential amount to be paid under the guarantee, the carrying value of the liability associated with the guarantee and any recourse of the guarantor to recover amounts paid under the guarantee from third parties. FIN 45 rescinds all the provisions of FIN 34, Disclosure of Indirect Guarantees of Indebtedness of Others; as it has been incorporated into the provisions of FIN 45. The provisions of FIN 45 are effective for all guarantees issued or modified subsequent to December 31, 2002. The disclosure requirements of FIN 45 are effective for the financial statements of interim and annual periods ending after December 15, 2002. Other than the previously disclosed MAPP guarantee, we do not have any commitments within the scope of FIN 45.

In January 2003, the FASB issued FASB Interpretation No. 46 (FIN 46), “Consolidation of Variable Interest Entities, an interpretation of ARB 51”. The primary objectives of FIN 46 are to provide guidance on the identification of entities for which control is achieved through means other than through voting rights (“variable interest entities” or “VIEs”) and how to determine when and which business enterprise should consolidate the VIE (the “primary beneficiary”). We are not the primary beneficiaries of any VIEs.

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 market risk in accordance with established policies, which may include entering into various derivative transactions. During the second quarter of 2001, we began utilizing 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.

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 2003 than in 2002, our interest expense would increase, and income before taxes would decrease by approximately $226,000. This amount has been determined by considering the impact of the hypothetical interest rates on our commercial paper balances as of December 31, 2002. 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.

Item 4. Controls and Procedures.

Within the 90-day period prior to the date of 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 required to be disclosed by us in the reports that we file or submit under the Exchange Act.

There have been no significant changes in our internal controls or in other factors that could significantly affect internal controls subsequent to the date of the evaluation described above.

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 24, 2003.

(b) The following persons were re-elected Directors of Empire to serve until the 2006 Annual Meeting of Stockholders:

M. W. McKinney (18,245,512 votes for; 307,578 withheld authority).

M. M. Posner (18,286,478 votes for; 266,612 withheld authority).

The following persons were elected Directors of Empire to serve until the 2006 Annual Meeting of Stockholders:

D. R. Laney (18,227,486 votes for; 275,604 withheld authority).

B. T. Mueller (18,244,234 votes for; 308,856 withheld authority).

The term of office as Director of the following other Directors continued after the meeting: F. E. Jeffries, J. S. Leon, M. F Chubb, R. C. Hartley, W. L. Gipson, and R. L. Lamb.

Item 5. Other Information.

At March 31, 2003, we had 797 full-time employees, including 153 Mid-America Precision Products employees. 328 of these employees are members of Local 1474 of The International Brotherhood of Electrical Workers (IBEW). On April 29, 2003, we and the IBEW entered into a new four-year labor agreement effective retroactively to November 1, 2002. The agreement provides, among other things, for a 3.25% increase in wages effective November 4, 2002, with additional minimum increases of 2.75% effective October 20, 2003 for the first year, effective November 1, 2004 for the second year, effective October 31, 2005 for the third year and effective November 17, 2006 for the fourth year.

At March 31, 2003, our ratio of earnings to fixed charges was 2.58x. See Exhibit (12) hereto.

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

(a) Exhibits.

(4) First Amendment to $100,000,000 Unsecured Credit Agreement, dated as of April 17, 2003, among Empire, UMB Bank, N.A., as arranger and administrative agent, Bank of America, N.A., as syndication agent, and the lenders named therein.

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

(99)(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.*

(99)(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 February 6, 2003, Empire filed, under Item 7. “Financial Statements and Exhibits,” a press release announcing our 2002 fourth quarter and twelve month ended December 31, 2002 earnings and the script for our earnings release conference call scheduled February 6, 2003.

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/ G. A. Knapp
		G. A. Knapp
		Vice President – Finance and Chief Financial Officer


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

May 14, 2003

CERTIFICATIONS

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

PURSUANT TO SECTION 302 OF THE

SARBANES-OXLEY ACT OF 2002

I, William L. Gipson, certify that:

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

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

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

4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

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

b) evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the “Evaluation Date”); and

c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

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

a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

6. The registrant’s other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date: May 14, 2003

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

CERTIFICATION OF CHIEF FINANCIAL OFFICER

PURSUANT TO SECTION 302 OF THE

SARBANES-OXLEY ACT OF 2002

I, Gregory A. Knapp, certify that:

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

b) evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the “Evaluation Date”); and

c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

Date: May 14, 2003

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

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

	For the quarterly period ended March 31, 2003

	or

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

	For the transition period from to .

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)