EMPIRE DISTRICT ELECTRIC CO - 10-Q Quarterly Report

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)

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

		For the quarterly period ended June 30, 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 .

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 August 1, 2003, 22,816,418 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

	Results of Operations.

	Liquidity and Capital Resources

	Contractual Obligations.

	Off-Balance Sheet Arrangements.

	Critical Accounting Policies.

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

THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED STATEMENT OF INCOME (UNAUDITED)

	Three Months Ended June 30,
	2003			2002
Operating revenues:
Electric	$	69,326,252		$	68,155,498
Water	355,506			271,975
Non-regulated	4,921,175			477,298
	74,602,933			68,904,771
Operating revenue deductions:
Operating expenses:
Fuel	12,948,176			11,590,132
Purchased power	15,096,260			14,585,443
Non-Regulated	5,129,534			962,734
Regulated - other	12,217,625			11,069,329
Total operating expenses	45,391,595			38,207,638

Maintenance and repairs	5,327,269			6,439,570
Depreciation and amortization	7,167,339			6,450,723
Provision for income taxes	1,597,953			2,116,082
Other taxes	3,883,283			3,711,052
	63,367,439			56,925,065

Operating income	11,235,494			11,979,706
Other income and deductions:
Interest income	14,878			19,658
Provision for other income taxes	28,921			24,844
Minority interest	(208,695		)	—
Other – net	(190,895		)	(100,524		)
	(355,791		)	(56,022		)
Income before interest charges	10,879,703			11,923,684
Interest charges:
Long-term debt – other	6,746,604			6,596,385
Trust preferred distributions by subsidiary holding solely parent debentures	1,062,500			1,062,500
Commercial paper	169,809			151,928
Allowance for borrowed funds used during construction	(97,924		)	(139,188		)
Other	97,973			225,543
	7,978,962			7,897,168
Net income applicable to common stock	$	2,900,741		$	4,026,516

Weighted average number of common shares outstanding	22,728,088			20,919,087

Basic and diluted earnings per weighted average share of common stock	$	0.13		$	0.19

Dividends per share of common stock	$	0.32		$	0.32

See accompanying Notes to Financial Statements.

THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED STATEMENT OF INCOME (UNAUDITED)

	Six Months Ended June 30,
	2003			2002
Operating revenues:
Electric	$	140,614,788		$	132,717,045
Water	681,195			529,870
Non-regulated	10,212,679			954,408
	151,508,662			134,201,323
Operating revenue deductions:
Operating expenses:
Fuel	21,711,668			25,870,684
Purchased power	33,632,904			29,341,620
Non-regulated	10,651,217			1,786,594
Regulated - other	23,456,810			21,188,891
Expenses related to terminated merger	—			1,524,355
Total operating expenses	89,452,599			79,712,144

Maintenance and repairs	10,120,152			12,525,507
Depreciation and amortization	13,982,256			12,935,026
Provision for income taxes	4,976,635			1,892,359
Other taxes	7,556,202			7,512,110
	126,087,844			114,577,146

Operating income	25,420,818			19,624,177
Other income and deductions:
Interest income	32,494			48,774
Provision for other income taxes	54,529			37,708
Minority interest	(305,765		)	—
Other - net	(376,271		)	(322,166		)
	(595,013		)	(235,684		)
Income before interest charges	24,825,805			19,388,493
Interest charges:
Long-term debt - other	13,483,894			13,193,134
Trust preferred distributions by subsidiary holding solely parent debentures	2,125,000			2,125,000
Commercial paper	248,071			291,962
Allowance for borrowed funds used during construction	(293,513		)	(239,957		)
Other	337,347			528,382
	15,900,799			15,898,521
Net income applicable to common stock	$	8,925,006		$	3,489,972

Weighted average number of common shares outstanding	22,668,198			20,355,121

Basic and diluted earnings per weighted average share of common stock	$	0.39		$	0.17

Dividends per share of common stock	$	0.64		$	0.64

See accompanying Notes to Financial Statements.

THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED STATEMENT OF INCOME (UNAUDITED)

	Twelve Months Ended June 30,
	2003			2002
Operating revenues:
Electric	$	302,469,537		$	277,478,486
Water	1,226,996			1,068,060
Non-regulated	19,513,801			1,807,069
	323,210,334			280,353,615
Operating revenue deductions:
Operating expenses:
Fuel	45,596,450			60,804,399
Purchased power	67,056,391			55,928,565
Non-regulated	20,775,644			2,814,786
Regulated - other	45,332,210			39,928,875
Expenses related to terminated merger	—			1,679,275
Total operating expenses	178,760,695			161,155,900

Maintenance and repairs	21,990,619			24,179,874
Depreciation and amortization	27,131,660			28,166,464
Provision for income taxes	16,475,073			5,540,623
Other taxes	16,219,538			14,396,321
	260,577,585			233,439,182

Operating income	62,632,749			46,914,433
Other income and deductions:
Allowance for equity funds used during construction	—			104,104
Interest income	71,055			113,229
Loss on plant disallowance	—			(4,087,066		)
Provision for other income taxes	97,619			1,563,121
Minority interest	(448,228		)	—
Other - net	(820,659		)	(791,476		)
	(1,100,213		)	(3,098,088		)
Income before interest charges	61,532,536			43,816,345
Interest charges:
Long-term debt	25,248,722			26,385,160
Trust preferred distributions by subsidiary holding solely parent debentures	4,250,000			4,250,000
Commercial paper	669,297			1,046,927
Allowance for borrowed funds used during construction	(624,365		)	121,791
Other	1,029,730			1,067,642
	30,573,384			32,871,520
Net income applicable to common stock	$	30,959,152		$	10,944,825

Weighted average number of common shares outstanding	22,580,923			19,133,160

Basic and diluted earnings per weighted average share of common stock	$	1.37		$	0.57

Dividends per share of common stock	$	1.28		$	1.28

See accompanying Notes to Financial Statements.

THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME (UNAUDITED)

	Three Months Ended June 30,
	2003			2002

Net income	$	2,900,741		$	4,026,516

Reclassification adjustments for gains/(losses) included in net income	490,238			(232,750		)
Change in fair market value of open derivative contracts for period	3,163,004			3,376,251
Income taxes	(1,388,232		)	(1,194,530		)
Net change in unrealized gain on derivative contracts	2,265,010			1,948,971

Comprehensive Income	$	5,165,751		$	5,975,487

	Six Months Ended June 30,
	2003			2002

Net income	$	8,925,006		$	3,489,972

Reclassification adjustments for gains/(losses) included in net income	(3,408,620		)	1,132,400
Change in fair market value of open derivative contracts for period	9,249,189			8,746,321
Income taxes	(2,219,416		)	(3,753,914		)
Net change in unrealized gain on derivative contracts	3,621,153			6,124,807

Comprehensive Income	$	12,546,159		$	9,614,779

	Twelve Months Ended June 30,
	2003			2002

Net income	$	30,959,152		$	10,944,825

Reclassification adjustments for gains/(losses) included in net income	(4,203,360		)	1,822,800
Change in fair market value of open derivative contracts for period	13,430,978			6,218,421
Income taxes	(3,506,495		)	(3,055,664		)
Net change in unrealized gain on derivative contracts	5,721,123			4,985,557

Comprehensive Income	$	36,680,275		$	15,930,382

See accompanying Notes to Financial Statements

THE EMPIRE DISTRICT ELECTRIC COMPANY CONSOLIDATED BALANCE SHEET (UNAUDITED)

	June 30, 2003		December 31, 2002
ASSETS
Plant and property, at original cost:
Electric	$	1,172,179,707	$	1,099,983,796
Water	8,603,531		8,400,720
Non-regulated	19,718,851		17,075,955
Construction work in progress	11,575,053		41,504,451
	1,212,077,142		1,166,964,922
Accumulated depreciation and amortization	386,080,983		372,892,648
	825,996,159		794,072,274
Current assets:
Cash and cash equivalents	4,484,729		14,439,227
Accounts receivable - trade, net	22,123,394		21,993,819
Accrued unbilled revenues	8,977,246		9,543,729
Accounts receivable - other	9,994,638		9,979,840
Fuel, materials and supplies	32,800,822		31,227,447
Unrealized gain in fair value of derivative contracts	11,263,768		5,983,490
Prepaid expenses	1,941,131		1,640,745
	91,585,728		94,808,297
Deferred charges:
Regulatory assets	45,255,976		36,169,683
Unamortized debt issuance costs	9,355,737		6,287,639
Unrealized gain in fair value of derivative contracts	23,511,232		16,949,388
Other	21,793,969		21,866,142
	99,916,914		81,272,852
Total Assets	$	1,017,498,801	$	970,153,423

CAPITALIZATION AND LIABILITIES:
Common stock, $1 par value, 22,799,528 and 22,567,179 shares issued and outstanding, respectively	$	22,799,528	$	22,567,179
Capital in excess of par value	264,276,248		260,559,197
Retained earnings (Note 2)	33,955,487		39,544,819
Accumulated other comprehensive income (net)	10,264,620		6,643,467
Total common stockholders’ equity	331,295,883		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	381,364		462,618
First mortgage bonds and secured debt	210,857,584		210,602,210
Unsecured debt	147,679,599		149,933,267
	408,918,547		410,998,095
Current liabilities:
Accounts payable and accrued liabilities	35,761,032		37,496,190
Commercial paper	74,350,000		22,541,000
Customer deposits	4,943,434		4,644,105
Interest accrued	3,157,764		3,990,184
Taxes accrued	1,969,599		—
Provision for rate refund	—		18,718,679
Obligations under capital lease	200,011		194,143
Unrealized loss in fair value of derivatives	444,140		64,000
	120,825,950		87,648,301
Noncurrent liabilities and deferred credits:
Regulatory liability	11,309,560		11,840,810
Deferred income taxes	110,563,256		103,144,549
Unamortized investment tax credits	5,988,468		6,131,000
Postretirement benefits other than pensions	4,609,776		4,928,965
Unrealized loss in fair value of derivative contracts	17,035,503		10,914,668
Minority interest	1,112,084		806,319
Other	5,839,774		4,426,054
	156,458,421		142,192,365
Total Capitalization and Liabilities	$	1,017,498,801	$	970,153,423

See accompanying Notes to Financial Statements.

THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED STATEMENT OF CASH FLOWS (UNAUDITED)

	Six Months Ended June 30,
	2003			2002
Operating activities:
Net income	$	8,925,006		$	3,489,972
Adjustments to reconcile net income to cash flows:
Depreciation and amortization	15,660,298			14,631,742
Pension expense (income)	682,449			(1,790,891		)
Deferred income taxes, net	4,683,611			633,862
Investment tax credit, net	(142,532		)	(73,502		)
Issuance of common stock and stock options for incentive plans	713,149			605,642
Unrealized loss on derivatives	(77,149		)	(317,660		)
Cash flows impacted by changes in:
Accounts receivable and accrued unbilled revenues	998,681			(509,040		)
Fuel, materials and supplies	(1,573,375		)	(996,434		)
Prepaid expenses and deferred charges	(746,124		)	371,505
Accounts payable and accrued liabilities	(1,703,967		)	(10,378,305		)
Customer deposits, interest and taxes accrued	1,436,478			3,589,603
Other liabilities and other deferred credits	551,213			1,459,758
Accumulated provision – rate refunds	(18,718,679		)	9,288,042

Net cash provided by operating activities	10,689,059			20,004,294

Investing activities:
Capital expenditures – regulated	(43,764,854		)	(32,752,902		)
Capital expenditures – non-regulated	(2,240,930		)	(1,899,123		)

Net cash used in investing activities	(46,005,784		)	(34,652,025		)

Financing activities:
Proceeds from issuance of common stock	3,262,610			54,199,267
Proceeds from issuance of senior notes	98,000,000			—
Long-term debt issuance costs	(3,574,420		)	—
Redemption of senior notes	(100,025,000		)	—
Premium paid on extinguished debt	(9,072,688		)	—
Discount on issuance of senior notes	(568,400		)	—
Common stock issuance costs	—			(2,475,233		)
Net change in commercial paper	51,809,000			6,500,000
Dividends	(14,514,338		)	(13,491,921		)
Repayment of long-term debt	45,463			(37,617,316		)

Net cash provided by financing activities	25,362,227			7,114,797

Net decrease in cash and cash equivalents	(9,954,498		)	(7,532,934		)

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

Cash and cash equivalents at end of period	$	4,484,729		$	3,907,341

See accompanying Notes to 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

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

Balance April 1, 2003	38,337,160
Changes April 1 through June 30, 2003:
Net income	2,900,741
Quarterly cash dividends on common stock: - $0.32 per share	(7,282,414		)

Balance June 30, 2003	$	33,955,487

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.

In the first half of 2003, we began amortizing the accumulated costs for our Conversant software and the value of the customer list obtained with our purchase of Joplin.com in accordance

with SFAS No. 142, “Goodwill and Other Intangible Assets,” which we adopted on January 1, 2002. This amortization will not have a material impact on our consolidated financial condition or results of operations.

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.

	As and for the quarter ended June 30,
	2003**					2002
	Non-Regulated			Total Company		Non-Regulated			Total Company
Statement of Income Information
Revenues	$	5,000,587	*	$	74,602,933	$	477,298		$	68,904,771
Operating income (loss)	$	(272,860	)	$	11,235,494	$	(396,509	)	$	11,979,706
Net income (loss)	$	(481,556	)	$	2,900,741	$	(396,509	)	$	4,026,516
Minority interest	$	208,695		$	208,695	$	—		$	—
Capital Expenditures
	$	606,868		$	16,088,820	$	688,770		$	18,912,515
Balance Sheet Information
Total assets	$	22,504,710		$	1,017,498,801	$	12,618,385		$	970,153,423
Minority interest	$	1,112,084		$	1,112,084	$	—		$	—

	For the six months ended June 30,
	2003**					2002
	Non-Regulated			Total Company		Non-Regulated			Total Company
Statement of Income Information
Revenues	$	10,343,288	*	$	151,508,662	$	954,408		$	134,201,323
Operating income (loss)	$	(584,860	)	$	25,420,818	$	(727,065	)	$	19,624,777
Net income (loss)	$	(890,930	)	$	8,925,006	$	(727,065	)	$	3,489,972
Minority interest	$	305,765		$	305,765	$	—		$	—
Capital Expenditures
	$	2,740,507		$	45,691,372	$	1,913,482		$	33,876,257

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

**Increases in 2003 revenues, assets and minority interest primarily reflect the acquisition of MAPP, a company specializing in close tolerance custom manufacturing for the aerospace, electronics, telecommunications and machinery industries.

Note 4 – 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. It requires us to record the estimated fair value of legal obligations associated with the retirement of tangible long-lived assets in the period in which the liabilities are incurred and to capitalize a corresponding amount as part of the book value of the related long-lived asset. In subsequent periods, we are required to adjust asset retirement obligations based on changes in estimated fair value, and the corresponding increases in asset book

values are depreciated over the useful life of the related asset. Uncertainties as to the probability, timing or cash flows associated with an asset retirement obligation affect our estimate of fair value.

Upon adoption of this standard on January 1, 2003, we 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. This liability will be accreted over the period up to the estimated settlement date. The balance at the end of the second quarter of 2003 was approximately $640,000.

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 have a material impact on our financial condition and results of operation.

In May 2003, the FASB issued SFAS No. 150 (FAS 150), “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity.” This statement requires that (1) financial instruments issued in the form of mandatorily redeemable shares, (2) financial instruments that, at inception, represents an obligation to repurchase the issuer’s shares or is an obligation indexed to the price of the company’s shares, and (3) financial instruments that embody an unconditional obligation, or a conditional obligation for an instrument other than an outstanding share, that the issuer must or may settle by issuing a variable number of equity shares; be classified as liabilities if at inception the monetary value is based on (1) a fixed amount, (2) variations in something other than the fair value of the issuer’s shares or (3) variations inversely related to the fair value of the issuer’s shares. This standard is effective for financial instruments entered into or modified after May 31, 2003, and otherwise is effective at the beginning of the first interim period beginning after June 15, 2003. We currently do not have any securities that will be impacted by this.

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 guarantee of a $2.5 million note issued by MAPP, we do not have any material commitments within the scope of FIN 45. See Item 2, “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Contractual Obligations.”

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 evaluating the impact of FIN 46 but do not at present believe we are the primary beneficiary of any VIEs.

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 and to manage certain interest rate exposure. See Note 6 and Note 7.

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 June 30, 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	$	11,263,768	Current liabilities	$	444,140

Noncurrent assets	$	23,511,232	Noncurrent liabilities	$	17,035,503

A $10,264,620 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 $6,291,219 on this gain is included in deferred taxes. These amounts will be adjusted cumulatively on a monthly basis during the determination periods beginning July 1, 2003 and ending on February 28, 2006. 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 June 30, 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 $0.6 million (pre-tax) for the quarter ended June 30, 2003, $2.3 million (pre-tax) for the six months ended June 30, 2003 and $3.3 million (pre-tax) for the twelve months ended June 30, 2003.

Note 6 – Long-Term Debt

On June 17, 2003, we issued $98 million aggregate principal amount of 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

will be capitalized as a financing fee and 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 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. 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 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 June 30, 2003. 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 June 30, 2003. However, $74 million of the facility as of that date was used to back up our commercial paper and was not available to be borrowed.

Note 7 – Commitments and Contingencies

By letters dated October 31, 2002, January 17, 2003 and June 26, 2003, Enron North America Corp. (Enron) and their counsel demanded that we pay Enron $6,113,850 (plus accrued interest at the rate of 6.0%), an amount that Enron claimed it is owed as a result of our early termination of all transactions under the Enfolio Master Firm Purchase/Sale Agreement dated June 1, 2001 between us and Enron. We dispute that any amounts are owed to Enron as a result of such termination and have responded to Enron stating that there was no contractual basis for Enron to assert that it was entitled to any such payment. We intend to vigorously oppose any attempt by Enron to collect the claimed amounts.

We have announced our intentions to redeem (subject to market and other conditions, including financing) our First Mortgage Bonds, 9.75% Series due 2020, aggregate principal amount of $2.25 million and our First Mortgage Bonds 7.25% Series due 2028, aggregate principal amount of $13.058 million in the summer or fall of 2003. We have also announced our intentions to redeem our First Mortgage Bonds 7.0% Series due 2023, aggregate principal amount of $45 million in October 2003. The funds necessary for the redemption of the 9.75% bonds and the 7.25% bonds are initially expected to come from short-term debt. We filed a shelf registration statement with the SEC on August 5, 2003 covering an aggregate of $200 million of our common stock, first mortgage bonds, unsecured debt securities and preference stock. The registration statement is not yet effective. Proceeds of one or more offerings of securities to be covered by this new shelf registration statement will be used to finance the redemption of the 7% bonds and to repay the short-term debt incurred in connection with the other redemptions (including the completed redemption of our Senior Notes, 7.70% Series due 2004). On May 16, 2003, we also entered into a Treasury Lock forward transaction with an outside counterparty to hedge the risk of changes in the first 60 semi-annual interest payment cash flows for $60 million of the intended issuances. The risks being hedged are attributable to changes in the 30-year benchmark Treasury rate (risk free rate) for the debt pricing. The Treasury Lock transaction will effectively lock in a yield on $60 million of the intended debt offering. We “mark-to-market” the fair market value of this contract at the end of each accounting period as specified in FAS 133, “Accounting for Derivative Instruments and Hedging Activities” and FAS 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities.” The fair market value of this contract at June 30, 2003 was $0.4 million net of tax and is included in Other Comprehensive Income. The before tax balance of $0.6 million is

included in the Unrealized Gain in Fair Value of Derivatives Contracts – Current balance on our Consolidated Balance Sheet. The Treasury Lock will expire on October 15, 2003 and will require a settlement payment to be made by us to the counterparty, or vice versa, depending on the underlying Treasury Rate on such date. If we complete the refinancings, any payment received by us will lower the effective yield on, and be accrued over the life of, the new securities, and any payment made by us will increase the issuance costs of, and be amortized over the life of, such securities. An increase or decrease of ¼% in the underlying Treasury Rate would cause a corresponding change in the settlement amount we would receive or pay of approximately $2 million. Based on the underlying Treasury Rate on July 31, 2003, we would receive a settlement payment of $7.1 million before taxes if the Treasury Lock had expired on that date.

Based on the performance of our pension plan assets through December 31, 2002, we expect to be required under the Employee Retirement Income Security Act of 1974 (ERISA) to fund approximately $0.3 million in 2004 and $2.0 million in 2005 in order to maintain minimum funding levels. These amounts are estimates and will likely change based on actual investment performance, any future pension plan funding and finalization of actuarial assumptions.

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, revenues, 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, six-month and twelve-month periods ended June 30, 2003, compared to the same periods ended June 30, 2002.

Electric Operating Revenues and Kilowatt-Hour Sales

Of our total electric operating revenues during the second quarter of 2003 approximately 35.8% were from residential customers, 31.0% from commercial customers, 17.5% from industrial customers, 4.5% from wholesale on-system customers, 6.1% from wholesale off-system transactions and 5.1% from miscellaneous sources, primarily transmission services. The percentage changes from the prior year periods in kilowatt-hour (“Kwh”) sales and operating revenues by major customer class were as follows:

	Kwh Sales						*Revenues
	Second Quarter		Six Months Ended		Twelve Months Ended		Second Quarter		Six Months Ended		Twelve Months Ended
Residential	(4.9	)%	1.6	%	4.3	%	0.4	%	7.3	%	8.5	%
Commercial	(1.4	)	0.7		0.9		4.1		6.6		5.0
Industrial	(3.3	)	0.7		2.7		1.5		6.7		6.6
Wholesale On-System	(6.3	)	(2.6	)	(0.1	)	7.5		0.7		(5.5	)
Total On-System	(3.4	)	0.8		2.5		5.4		6.6		6.3

*Revenues exclude amounts collected under the Interim Energy Charge 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 decreased 3.4% during the second quarter of 2003 over the second quarter of 2002 primarily due to milder temperatures during June 2003 than in June 2002. Total cooling degree days (the number of degrees that the average temperature for that period was above 65° F) for the second quarter of 2003 were 23.2% less than the 20-year average and 15.9% less than the same period last year. Despite the decreased Kwh sales, revenues for our on-system customers increased $1.4 million (2.3%) as a result of the Missouri, Kansas and FERC rate increases discussed below.

Residential and commercial Kwh sales were down during the second quarter of 2003 due mainly to the milder temperatures discussed above. Residential and commercial revenues increased, however, as a result of 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, decreased primarily as a result of an adjustment for a billing correction made in April 2003. Industrial revenues, however, increased as a result of the 2002 Missouri and Kansas rate increases.

On-system wholesale Kwh sales decreased during the second quarter of 2003 reflecting the weather conditions discussed above. Also contributing to the decrease was the change in customer status in June 2003 of one of our on-system wholesale customers who elected to go off-system and purchase power from us at market-based rates. Revenues received from this customer, which comprised 5-6% of our on-system wholesale sales in both 2002 and 2001, are now included in our

off-system sales. Revenues associated with these Kwh sales increased as a result of the FERC rate increase that became effective May 1, 2003.

For the six months ended June 30, 2003, Kwh sales to our residential and commercial customers increased, reflecting colder temperatures during the first quarter of 2003 as compared to the same period in 2002. Residential and commercial revenues increased during the second quarter of 2003 reflecting the increased sales, as well as the December 2002 Missouri rate increase and July 2002 Kansas rate increase. Industrial Kwh sales increased for the six month period reflecting better economic conditions in the first quarter of 2003 as compared to the first quarter of 2002 when our service territory experienced a general slowdown in economic activity. Related industrial revenues increased due to the positive effects of the 2002 Missouri and Kansas rate increases. On-system wholesale Kwh sales decreased reflecting the change in customer status of one of our on-system customers to off-system as discussed above. Revenues associated with these sales increased as a result of the FERC rate increase that became effective May 1, 2003.

For the twelve months ended June 30, 2003, residential and commercial Kwh sales increased, reflecting the colder temperatures during the fourth quarter of 2002 and the first quarter of 2003 (during our heating seasons) and warmer temperatures during September 2002 (during our air conditioning season) as compared to the same periods ended the previous year. Residential and commercial revenues increased during this period due to the increased sales and the 2002 Missouri and Kansas rate increases. Industrial sales increased during the twelve-month period reflecting increased sales in August through November 2002 and the first quarter of 2003 because of better economic conditions as compared to the same period a year earlier. Revenues increased reflecting the 2002 Missouri and Kansas rate increases. On-system wholesale Kwh sales decreased slightly during the twelve-month period while associated revenues decreased more as a result of the operation of the fuel adjustment clause applicable to these FERC regulated sales. This clause permits the pass through to customers of changes in fuel and purchased power costs.

Rate Matters

The following table sets forth information regarding electric and water rate increases affecting the revenue comparisons discussed above:

Jurisdiction	Annual Date Requested	Percent Increase Granted		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

*Effective for bills rendered on or after August 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%. On August 1, 2003 a Unanimous Stipulation and Agreement was approved by the Oklahoma Corporation Commission providing an annual increase in rates for our Oklahoma customers of approximately $766,500, or 10.99%, effective for bills rendered on or after August 1, 2003. This reflects a rate of return on equity of 11.27%.

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.

The following table sets forth information regarding these sales and related expenses:

	2003						2002
(in millions)	Second Quarter		Six Months Ended		Twelve Months Ended		Second Quarter		Six Months Ended		Twelve Months Ended

Revenues	$	5.6	$	9.6	$	21.8	$	5.7	$	9.7	$	13.5
Expenses	3.4		5.7		12.5		3.7		6.6		8.2
Net Revenue	$	2.2	$	3.9	$	9.3	$	2.0	$	3.1	$	5.3

The increase in revenues for the twelve months ended June 30, 2003 as compared to the same period in 2002 resulted primarily from term purchases of firm energy that began in January of 2002 and continued through the second 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. To the extent that we are allocated 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. Revenues received from off-system transmission customers are reflected in electric operating revenues and the related charges expensed.

Prior to the time we began taking Network Integration Transmission Service under the SPP’s Open Access Transmission Tariff, we had an agreement with Kansas City Power & Light (KCP&L) for transmission service from the Iatan plant. We believed we had the right to terminate the service under the older Iatan transmission agreement, whereas KCP&L contended that we could not. While we were working to resolve this dispute, we ceased scheduling service from KCP&L but continued to accrue (but not pay) the monthly amount we had paid under the original contract terms. We have reached a settlement with KCP&L to pay the amount we have been accruing since October 2002, which is now approximately $0.8 million, and to continue the service agreement with KCP&L through March 2004, at which time we will be released from the original agreement. The additional cost for continuing the service agreement through March 2004 will be approximately $0.653 million paid in monthly payments equal to the amount we have been accruing each month.

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 second quarter of 2003, total non-regulated operating revenue increased approximately $4.4 million while total non-regulated operating expense increased approximately $4.2 million compared with 2002. For the six months ended June 2003, total non-regulated operating revenue increased approximately $9.3 million while total non-regulated operating expense increased approximately $8.9 million. For the twelve-months ended June 2003, total non-regulated operating revenue increased approximately $17.7 million while total non-regulated operating expense increased approximately $18.0 million. The increase in both revenues and expenses for all 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 expenses for the periods presented was also due to the activities of our wholly owned subsidiary, Conversant, Inc., a software company that began business in early 2002. In June 2003, Conversant, Inc. signed a contract with a prospective customer and we expect Conversant, Inc. to begin contributing to non-regulated revenues during the latter half of 2003, subject to the successful completion of various milestones including a pilot program currently in progress. 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 $0.5 million net loss in the second quarter of 2003 as compared to a $0.4 million net loss in the second quarter of 2002, a net loss of $0.9 million for the six months ended June 30, 2003 as compared to a net loss of $0.7 million for the same period during 2002 and a net loss of $1.7 million for the twelve months ended June 30, 2003 as compared to a net loss of $1.0 million for the twelve months ended June 30, 2002. The increase in net loss for all three periods presented was due primarily to the Conversant, Inc. expenditures discussed above.

Operating Revenue Deductions

During the second quarter of 2003, total operating expenses increased approximately $7.2 million (18.8%) compared with the same period last year due mainly to the approximately $4.2 million increase in non-regulated operating expense described above.

Total fuel costs increased approximately $1.4 million (11.7%) during the second quarter of 2003 as compared to the same period in 2002 while purchased power costs increased approximately $0.5 million (3.5%) during the period. The increase in fuel costs reflects an 80% increase in generation by the State Line Combined Cycle (SLCC) and the Energy Center units in April 2003 over April 2002 when some of our coal-fired units were out of service for routine maintenance outages. In April 2003, the Iatan Plant underwent a planned boiler outage, the Riverton Plant’s Unit No. 7 had a 12-day scheduled spring maintenance outage and Unit No. 8 was unavailable due to an extended maintenance outage that ran from February 14 until May 14. Our natural gas costs per mcf were also 18.8% higher during April 2003 than in April 2002. The increase in purchased power costs reflects the term purchases of firm energy previously discussed.

Other operating expenses increased $1.1 million (10.4%) during the period due to a $1.0 million increase in pension expense resulting from a decline in the value of invested pension funds. We expect pension expense to approximate $0.7 million in 2003 due to the decline in the value of those funds. Additionally, we expect to be required under ERISA to fund approximately $0.3 million in 2004 and $2.0 million in 2005 to maintain minimum funding levels. Absent a substantial recovery in the equity markets, we expect pension expense and cash funding requirements to substantially increase over the next several years. Maintenance and repair expense decreased approximately $1.1

million (17.3%) during the quarter, primarily due to a $1.8 million true-up credit from Siemens Westinghouse in June 2003 related to our maintenance contract entered into in July 2001 for the State Line Combined Cycle Unit. Monthly payments on this contract have been based on an estimated number of starts. Actual starts during the last twelve months, however, were significantly less than originally estimated resulting in the June 2003 true up credit. This credit was partially offset by costs associated with the maintenance outages at the Riverton and Iatan plants. Our transmission and distribution systems in our Kansas and Missouri service territories suffered an estimated $7.9 million of property damage from tornadoes that occurred on May 4, 2003 that initially disrupted power to an estimated 30,000 customers. Approximately $5.6 million of this amount was recorded as capital expenditures as of June 30, 2003. The majority of our related reconstruction costs were either capitalized or are expected to be reimbursed by insurance with only approximately $0.2 million being expensed. No amounts have been recorded to date for any potential insurance recoveries.

Depreciation and amortization expense increased approximately $0.7 million (11.1%) during the quarter due to increased plant in service. The provision for income taxes decreased $0.5 million (24.5%) during the second quarter of 2003 due to a decrease in taxable income. Our effective federal income tax rate for the second quarter of 2003 was 35.1% as compared to 34.2% for the second quarter of 2002. Other taxes increased approximately $0.2 million (4.6%) during the second quarter of 2003 due mainly to increased property taxes reflecting our additions to plant in service.

For the six months ended June 30, 2002, total operating expenses were up approximately $9.7 million (12.2%) due largely to the approximately $8.9 million increase in non-regulated operating expense described above. Purchased power costs increased $4.3 million (14.6%) but were offset by a $4.2 million (16.1%) decrease in total fuel costs for the six-month period ending June 30, 2003. The increase in purchased power costs reflected increased demand resulting from colder temperatures in the first quarter of 2003, higher purchased power costs in the first quarter of 2003 and our inability at times during extremely 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 six months ended June 30, 2003 primarily due to $4.6 million of net gains recognized in the first quarter of 2003 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 had been financially hedged but were 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. See Note 5 — Risk Management and Derivative Financial Instruments under Notes to Consolidated Financial Statements (Unaudited).

Other operating expenses for the first six months of 2003 increased approximately $2.3 million (10.7%) primarily as a result of a $1.8 million increase in pension expense resulting from a decline in the value of invested pension funds. Other operating expenses for the six months ended June 30, 2002 included $1.5 million (largely severance costs) relating to the terminated merger with Aquila, Inc.

Maintenance and repair expense decreased $2.4 million (19.2%) for the six months ended June 30, 2003 compared to the same period in 2002 primarily due to the $1.8 million true-up credit from Siemens Westinghouse described above. Lower payments during the first half of 2003 on our long-term operating plant maintenance contracts as compared to the first half of 2002 when we were making additional payments on the Energy Center and State Line Unit No. 1 contract for outage services also contributed to the decrease. Depreciation and amortization expense increased approximately $1.0 million (8.1%) during the six-month period due to increased plant in service. Total provisions for income taxes increased $3.1 million (163.0%) due to an increase in taxable income. Our effective federal income tax rate for the first six months of 2003 was 35.5% as

compared to 34.7% for the first six months of 2002. Other taxes were virtually the same for both six month periods.

During the twelve months ended June 30, 2003, total operating expenses increased approximately $17.6 million (10.9%) compared to the same period in 2002 due mainly to the $18.0 million increase in non-regulated operating expense described above. Total purchased power costs increased approximately $11.1 million (19.9%) while total fuel costs decreased approximately $15.2 million (25.0%) during the twelve-month 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 third quarter of 2002, higher purchased power costs in the first quarter of 2003, our inability at times during extremely cold weather to get natural gas delivered, and the term purchases of firm energy previously discussed. Total fuel costs decreased during the twelve months ended June 30, 2003 reflecting the positive results of our hedging efforts during the period, a $1.2 million reduction to fuel expense resulting from an unrealized gain on ineffective hedges in December 2002, low natural gas prices in the third quarter of 2002 and less generation by our gas-fired units due in large part to the term purchases of firm energy. Other operating expenses increased approximately $5.4 million (13.5%) during the twelve months ended June 30, 2003, compared to the same period last year primarily as a result of a $2.9 million decrease in pension income due to a decline in the value of invested pension funds. Other operating expenses for the twelve months ended June 30, 2002 also included $1.7 million of expenses related to the terminated merger discussed above.

Maintenance and repair expense decreased approximately $2.2 million (9.1%) during the twelve months ended June 30, 2003 compared to the prior period, primarily due to the $1.8 million true-up credit from Siemens Westinghouse and lower payments during the first half of 2003 than in 2002 on our long-term operating plant maintenance contracts discussed above. Depreciation and amortization expense decreased approximately $1.0 million (3.7%) due to the lower depreciation rates put into effect during the fourth quarter of 2001 as a result of the October 2001 Missouri rate order. Total provision for income taxes increased $10.9 million (197.4%) due to increased taxable income during the current period. Our effective federal income tax rate for the twelve months ended June 30, 2003 was 34.6% as compared to 26.7% for the twelve months ended June 30, 2002. Other taxes increased approximately $1.8 million (12.7%) due mainly to increased property taxes.

Nonoperating Items

Total allowance for funds used during construction (AFUDC) was virtually the same for the three months and six months periods ended June 30, 2003 and 2002 but increased $0.6 million during the twelve months ended June 2003 over the same period in 2002.

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 June 30, 2002 after considering the tax effect on this write-down was $2.5 million.

Total interest charges on long-term debt increased $0.2 million (2.3%) for the second quarter and $0.3 million (2.2%) for the six months ended June 30, 2003 when compared to the same periods ended in 2002 reflecting the sale of $50 million of 7.05% senior notes in an underwritten public offering on December 23, 2002. Total interest charges on long-term debt decreased $1.1 million (4.3%) for the twelve months ended June 30, 2003 over the corresponding period ended last year reflecting the maturity of $37.5 million of our first mortgage bonds in July 2002. Commercial paper interest was virtually the same for the second quarters of 2003 and 2002 as well as for the six month periods ended June 30, 2003 and 2002 but decreased $0.4 million for the twelve months ended June 30, 2003 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 as 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 change in unrealized gain of $2.3 million for the second quarter of 2003 as compared to a net change of $1.9 million for the second quarter of 2002, a net change in unrealized gain of $3.6 million for the six months ended June 30, 2003 as compared to a net change of $6.1 million for the six months ended June 30, 2002.and a net change in unrealized gain of $5.7 million for the twelve months ended June 30, 2003 as compared to a net change of $5.0 million for the twelve months ended June 30, 2002.

Earnings

For the second quarter of 2003, basic and diluted earnings per weighted average share of common stock were $0.13 compared to $0.19 during the second quarter of 2002. Earnings per share decreased primarily as a result of decreased sales due to milder temperatures during June 2003 as compared to June 2002, partially offset by the December 2002 Missouri rate increase, the July 2002 Kansas rate increase and the May 2003 FERC rate increase. Also negatively impacting 2003 second quarter earnings was a $1.9 million net increase in total fuel and purchased power costs and the $1.0 million increase in pension expense, offset to some extent by the decline in maintenance expense discussed above.

Basic and diluted earnings per weighted average share for the six months ended June 30, 2003, were $0.39 compared to $0.17 for the six months ended a year earlier. This increase in earnings per share was primarily due to increased sales resulting from colder temperatures during the first quarter of 2003, the December 2002 Missouri rate increase, the July 2002 Kansas rate increase and the May 2003 FERC rate increase. Negatively impacting earnings for first six months of 2002 were merger costs of $1.1 million (net of taxes).

Basic and diluted earnings per weighted average share of common stock for the twelve months ended June 30, 2003, were $1.37 compared to $0.57 for the twelve months ended in 2002. The increase was primarily due to the Missouri, Kansas and FERC rate increases, favorable weather during the fourth quarter of 2002 and the first quarter of 2003, a significant increase in off-system sales, a $4.1 million net decrease in total fuel and purchased power costs, and a $2.2 million decrease in maintenance expense. Negatively impacting earnings for the twelve months ended June 30, 2002 were $1.1 million in merger costs net of related income taxes, and a one-time non-cash charge of $2.5 million (net of income taxes) in the third quarter of 2001 for disallowed capital costs related to the construction of the State Line Combined Cycle Unit.

LIQUIDITY AND CAPITAL RESOURCES

Our capital expenditures totaled $16.1 million during the second quarter of 2003 compared to $18.9 million for the same period in 2002. For the six months ended June 30, 2003, capital expenditures totaled $45.7 million compared to $33.9 million for the same period in 2002.

A breakdown of these capital expenditures for the quarter and six months ended June 30, 2003 is as follows:

	Quarter Ended June 30, 2003		Six Months Ended June 30, 2003
Distribution and transmission system additions	$	6.9	$	13.8
FT8 peaking units - Energy Center	0.8		20.4
Additions and replacements - Asbury, Iatan and Riverton	1.1		1.6
May tornado damage	5.7		5.7
Fiber optics (non-regulated)	0.4		1.2
Other	1.2		3.0
Total	$	16.1	$	45.7

For the second quarter and first six months of 2003, less than 1% of our capital expenditures were paid with internally generated funds (funds provided by operating activities less dividends paid). 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 capital 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 $20.4 million in the first six months of 2003 on these units (including AFUDC).

Our net cash flows provided by operating activities decreased $9.3 million during the first six months of 2003 as compared to the first six months 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 $5.4 million increase in net income and a $1.5 million increase due to changes in accounts receivable and accrued unbilled revenues during the first half of 2003 reflecting increased sales during the six months ended June 30, 2003 as compared to the same period in 2002 as well as the 2002 Missouri and Kansas rate increases and the 2003 FERC rate increase.

Our net cash flows used in investing activities increased $11.4 million during the first six months 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. The remainder of the change in investing activities was the result of retirements and the net effects of acquisitions.

Our net cash flows provided by financing activities increased $18.2 million during the first six months of 2003 as compared to 2002 due to a $98 million issuance of Senior Notes and a $45.3 million increase in short-term debt partially offset by $109.8 million in redemption and discount costs for the redemption in June 2003 of $100 million of our 2004 Senior Notes, 7.70% Series due 2004.

We currently expect that internally generated funds (funds provided by operating activities less dividends paid) 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 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).

Based on the performance of our pension plan assets through December 31, 2002, we expect to be required under the Employee Retirement Income Security Act of 1974 (ERISA) to fund

approximately $0.3 million in 2004 and $2.0 million in 2005 in order to maintain minimum funding levels. These amounts are estimates and will likely change based on actual investment performance, any future pension plan funding and finalization of actuarial assumptions.

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 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 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 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 will be capitalized as a financing fee and amortized over the life of the 2013 Notes, along with the $9.1 million redemption premium paid on the Senior Notes.

On August 5, 2003, we filed a shelf registration statement with the SEC covering an aggregate of $200 million of our common stock, first mortgage bonds, unsecured debt securities and preference stock. The registration statement is not yet effective. Proceeds of one or more offerings of securities (aggregating approximately $70 million) to be covered by this new shelf registration statement will be used to finance the redemption of the 7% bonds and to repay the short-term debt incurred in connection with the other redemptions as discussed in Note 6 and Note 7 of Notes to the Financial Statements. On May 16, 2003, we also entered into a Treasury Lock forward transaction with an outside counterparty to hedge the risk of changes in the first 60 semi-annual interest payment cash flows for $60 million of the intended issuances. The risks being hedged are attributable to changes in the 30-year benchmark Treasury rate (risk free rate) for the debt pricing. The Treasury Lock transaction will effectively lock in a yield on $60 million of the intended debt offering at a level which is specified upon execution of the transaction. We “mark-to-market” the fair market

value of this contract at the end of each accounting period as specified in FAS 133, “Accounting for Derivative Instruments and Hedging Activities” and FAS 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities.” The fair market value of this contract at June 30, 2003 was $0.4 million net of tax and is included in Other Comprehensive Income. The before tax balance of $0.6 million is included in the Unrealized Gain in Fair Value of Derivatives Contracts — Current balance on our Consolidated Balance Sheet. The Treasury Lock will expire on October 15, 2003 and will require a settlement payment to be made by us to the counterparty, or vice versa, depending on the underlying Treasury Rate on such date. If we complete the refinancings, any payment received by us will lower the effective yield on, and be accrued over the life of, the new securities, and any payment made by us will increase the issuance costs of, and be amortized over the life of, such securities. An increase or decrease of ¼% in the underlying Treasury Rate would cause a corresponding change in the settlement amount we would receive or pay of approximately $2 million. Based on the underlying Treasury Rate on July 31, 2003, we would receive a settlement payment of $7.1 million before taxes if the Treasury Lock had expired on that date.

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 June 30, 2003 would permit us to issue approximately $237.2 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 circumstances, when we issue new first mortgage bonds against first mortgage bonds which have been, or are to be, retired.

As of June 30, 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+

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 (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, commercial paper or other securities or make the marketing of such securities more difficult.

Recently Issued Accounting Standards

The information in Note 4 to the Financial Statements is incorporated herein by reference.

CONTRACTUAL OBLIGATIONS

Set forth below is information summarizing our contractual obligations as of June 30, 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)	$	359.5	$	—	$	10.0	$	—	$	349.5
Trust Preferred Securities	50.0		—		—		—		50.0
Capital Lease Obligations	0.6		0.2		0.4		—		—
Operating Lease Obligations	1.2		0.6		0.6		—		—
Purchase Obligations*	269.0		43.2		74.9		56.8		94.1
Other Long-Term Liabilities**	3.2		0.3		1.0		1.9		—

Total Contractual Obligations	$	683.5	$	44.3	$	86.9	$	58.7	$	493.6

*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 $2.5 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. Based on the performance of our pension plan assets through December 31, 2002, we expect to be required under ERISA to fund approximately $0.3 million in 2004 and $2.0 million in 2005 in order to maintain minimum funding levels. These amounts are estimates and may change based on actual stock market performance, any future pension plan funding and finalization of actuarial assumptions. 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 August 4, 2003, 86% of our anticipated volume of natural gas usage for the remainder of year 2003 is hedged at an average price of $2.78 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, 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 and approximately 5% of our anticipated volume of natural gas usage for the year 2007 is hedged at an average price of $4.20 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.

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.

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 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 control over financial reporting that could significantly affect internal control over financial reporting 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 our 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 Director 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.

On April 29, 2003, we and the Local 1474 of The International Brotherhood of Electrical Workers (IBEW) entered into a new four-year labor agreement effective retroactively to November 1, 2002. (As of March 31, 2003, we had 328 full-time employees who were members of the Local 1474). 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 June 30, 2003, our ratio of earnings to fixed charges was 2.55x. See Exhibit (12) hereto.

Effective August 4, 2003, the transfer agent and registrar for our common stock, as well as the rights agent under our Rights Agreement and administrator for our Dividend Reinvestment Plan, is Wells Fargo Bank Minnesota, N.A.

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

(a) Exhibits.

(12) Computation of Ratios 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 May 16, 2003 and filed May 21, 2003, Empire filed, under Item 5. “Other Events” and Item 7. “Financial Statements and Exhibits,” press releases announcing, among other matters, our plans to redeem certain outstanding debt securities, issue new senior unsecured notes and file a new $200 million shelf registration statement and announcing the calling for redemption of all $100 million aggregate principal amount of its Senior Notes, 7.70% Series due 2004.

(2) In a current report dated June 10, 2003 and filed July 29, 2003, Empire filed, under Item 5. “Other Events” and Item 7. “Financial Statements and Exhibits,” its Securities Resolution No. 4 dated as of June 10, 2003 under the Indenture for Unsecured Securities, dated as of September 10, 1999 between Empire and Wells Fargo Bank Minnesota, N.A.

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

August 13, 2003