EMPIRE DISTRICT ELECTRIC CO - 10-Q Quarterly Report

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)

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

		For the quarterly period ended September 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 November 1, 2003, 22,894,296 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 – (none)

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 September 30,
	2003			2002
Operating revenues:
Electric	$	95,769,637		$	95,680,705
Water	378,036			283,933
Non-regulated	4,881,352			3,858,777
	101,029,025			99,823,415
Operating revenue deductions:
Fuel	20,480,833			16,995,479
Purchased power	13,166,031			15,585,596
Regulated – other (Note 8)	12,021,920			10,738,407
Non-regulated	5,134,202			3,865,357
Maintenance and repairs	4,646,214			5,958,838
Depreciation and amortization	7,328,688			6,565,720
Provision for income taxes	9,067,681			9,611,253
Other taxes	4,562,845			4,441,750
	76,408,414			73,762,400

Operating income	24,620,611			26,061,015
Other income and deductions:
Interest income	9,146			21,933
Provision for other income taxes	42,141			(125,272		)
Minority interest	(135,266		)	(111,708		)
Other non-operating income	43,171			—
Other non-operating expense	(234,584		)	(147,650		)
	(275,392		)	(362,697		)
Interest charges:
Long-term debt — other	6,245,316			5,835,209
Trust preferred distributions by subsidiary holding solely parent debentures	1,062,500			1,062,500
Commercial paper	218,300			201,088
Allowance for borrowed funds used during construction	(30,451		)	(152,784		)
Other	86,909			365,713
	7,582,574			7,311,726
Net income applicable to common stock	$	16,762,645		$	18,386,592

Weighted average number of common shares outstanding	22,826,643			22,455,447

Basic and diluted earnings per weighted average share of common stock	$	0.73		$	0.82

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)

	Nine Months Ended September 30,
	2003			2002
Operating revenues:
Electric	$	236,384,426		$	228,397,751
Water	1,059,230			813,803
Non-regulated	15,094,030			4,813,185
	252,537,686			234,024,739
Operating revenue deductions:
Fuel	42,192,501			42,866,163
Purchased power	46,798,935			44,927,215
Regulated – other (Note 8)	35,478,730			31,927,298
Non-regulated	15,686,234			5,651,951
Merger related expenses	—			1,524,355
Maintenance and repairs	14,766,366			18,484,345
Depreciation and amortization	21,310,943			19,500,746
Provision for income taxes	14,044,316			11,503,613
Other taxes	12,119,047			11,953,860
	202,397,072			188,339,546

Operating income	50,140,614			45,685,193
Other income and deductions:
Interest income	41,640			70,707
Provision for other income taxes	96,670			(87,565		)
Minority interest	(441,031		)	(111,708		)
Other non-operating income	42,867			41,808
Other non-operating expense	(610,551		)	(511,624		)
	(870,405		)	(598,382		)
Interest charges:
Long-term debt - other	19,817,375			19,028,343
Trust preferred distributions by subsidiary holding solely parent debentures	3,187,500			3,187,500
Commercial paper	466,371			493,050
Allowance for borrowed funds used during construction	(323,965		)	(392,741		)
Other	435,277			894,096
	23,582,558			23,210,248
Net income applicable to common stock	$	25,687,651		$	21,876,563

Weighted average number of common shares outstanding	22,721,594			21,062,923

Basic and diluted earnings per weighted average share of common stock	$	1.13		$	1.04

Dividends per share of common stock	$	0.96		$	0.96

See accompanying Notes to Financial Statements.

THE EMPIRE DISTRICT ELECTRIC COMPANY
CONSOLIDATED STATEMENT OF INCOME (UNAUDITED)

	Twelve Months Ended September 30,
	2003			2002
Operating revenues:
Electric	$	302,558,469		$	290,113,498
Water	1,321,099			1,058,392
Non-regulated	20,536,375			5,183,899
	324,415,943			296,355,789
Operating revenue deductions:
Operating expenses:
Fuel	49,081,804			55,518,965
Purchased power	64,636,827			58,706,796
Regulated – other (Note 8)	46,615,723			41,537,667
Non-regulated	21,945,304			6,285,062
Merger related expenses	—			1,639,432
Maintenance and repairs	20,677,995			25,790,562
Depreciation and amortization	27,894,627			26,365,342
Provision for income taxes	15,930,704			11,117,933
Other taxes	16,340,633			14,847,016
	263,123,617			241,808,775

Operating income	61,292,326			54,547,014
Other income and deductions:
Allowance for equity funds used during construction	—			94,331
Interest income	58,268			93,358
Provision for other income taxes	264,235			(52,586		)
Minority interest	(471,785		)	(111,708		)
Other non-operating income	117,014			41,808
Other non-operating expense	(981,436		)	(706,200		)
	(1,013,704		)	(640,997		)
Interest charges:
Long-term debt - other	25,746,994			25,625,241
Trust preferred distributions by subsidiary holding solely parent debentures	4,250,000			4,250,000
Commercial paper	686,510			742,950
Allowance for borrowed funds used during construction	(502,032		)	117,425
Other	761,945			1,197,691
	30,943,417			31,933,307
Net income applicable to common stock	$	29,335,205		$	21,972,710

Weighted average number of common shares outstanding	22,674,485			20,336,656

Basic and diluted earnings per weighted average share of common stock	$	1.29		$	1.08

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 September 30,
	2003			2002

Net income	$	16,762,645		$	18,386,592

Reclassification adjustments for gains/(losses) included in net income	(2,546,123		)	(842,190		)
Change in fair market value of open derivative contracts for period	(1,737,522		)	663,791
Income taxes	1,627,786			67,792
Net change in unrealized gain (loss) on derivative contracts	(2,655,859		)	(110,607		)

Comprehensive Income	$	14,106,786		$	18,275,985

	Nine Months Ended September 30,
	2003			2002

Net income	$	25,687,651		$	21,876,563

Reclassification adjustments for gains/(losses) included in net income	(5,954,743		)	290,210
Change in fair market value of open derivative contracts for period	7,511,667			9,410,112
Income taxes	(591,630		)	(3,686,122		)
Net change in unrealized gain on derivative contracts	965,294			6,014,200

Comprehensive Income	$	26,652,945		$	27,890,763

	Twelve Months Ended September 30,
	2003			2002

Net income	$	29,335,205		$	21,972,710

Reclassification adjustments for gains/(losses) included in net income	(5,907,293		)	980,610
Change in fair market value of open derivative contracts for period	11,029,665			8,058,212
Income taxes	(1,946,501		)	(3,434,752		)
Net change in unrealized gain on derivative contracts	3,175,871			5,604,070

Comprehensive Income	$	32,511,076		$	27,576,780

See accompanying Notes to Financial Statements

THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEET (UNAUDITED)

	September 30, 2003		December 31, 2002
ASSETS
Plant and property, at original cost:
Electric	$	1,181,113,942	$	1,099,983,796
Water	8,717,542		8,400,720
Non-regulated	20,465,642		17,075,955
Construction work in progress	8,376,640		41,504,451
	1,218,673,766		1,166,964,922
Accumulated depreciation and amortization	387,526,002		372,892,648
	831,147,764		794,072,274
Current assets:
Cash and cash equivalents	3,319,592		14,439,227
Accounts receivable - trade, net	29,618,639		21,993,819
Accrued unbilled revenues	6,556,248		9,543,729
Accounts receivable – other (Note 7)	9,231,766		9,979,840
Fuel, materials and supplies	29,397,339		31,227,447
Unrealized gain in fair value of derivative contracts (Notes 3 and 4)	10,317,093		5,983,490
Prepaid expenses	3,179,990		1,640,745
	91,620,667		94,808,297
Deferred charges:
Regulatory assets (Note 6)	44,728,895		36,169,683
Unamortized debt issuance costs	9,283,665		6,287,639
Unrealized gain in fair value of derivative contracts (Notes 3 and 4)	16,972,150		16,949,388
Other	22,112,645		21,866,142
	93,097,355		81,272,852
Total Assets	$	1,015,865,786	$	970,153,423

CAPITALIZATION AND LIABILITIES:
Common stock, $1 par value, 22,876,302 and 22,567,179 shares issued and outstanding, respectively	$	22,876,302	$	22,567,179
Capital in excess of par value	266,095,655		260,559,197
Retained earnings	43,415,669		39,544,819
Accumulated other comprehensive income (net) (Notes 3 and 4)	7,608,760		6,643,467
Total common stockholders’ equity	339,996,386		329,314,662
Long-term debt (Note 4):
Company obligated manditorily redeemable trust preferred securities of subsidiary holding solely parent debentures	50,000,000		50,000,000
Obligations under capital lease	339,821		462,618
First mortgage bonds and secured debt	150,560,383		210,602,210
Unsecured debt	147,678,710		149,933,267
	348,578,914		410,998,095
Current liabilities:
Accounts payable and accrued liabilities	25,078,190		37,259,318
Commercial paper	59,000,000		22,541,000
Customer deposits	5,115,608		4,644,105
Interest accrued	7,761,895		3,990,184
Taxes accrued	3,603,432		—
Provision for rate refund	—		18,718,679
Obligations under capital lease	203,011		194,143
Unrealized loss in fair value of derivatives (Notes 3 and 4)	20,550		64,000
Current maturities of long-term debt	60,603,957		236,872
	161,386,643		87,648,301
Noncurrent liabilities and deferred credits:
Regulatory liability	15,014,150		11,840,810
Deferred income taxes	119,217,658		103,144,549
Unamortized investment tax credits	5,680,986		6,131,000
Postretirement benefits other than pensions	4,636,409		4,928,965
Unrealized loss in fair value of derivative contracts (Notes 3 and 4)	14,192,916		10,914,668
Minority interest	1,247,350		806,319
Other	5,914,374		4,426,054
	165,903,843		142,192,365
Total Capitalization and Liabilities	$	1,015,865,786	$	970,153,423

See accompanying Notes to Financial Statements.

THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED STATEMENT OF CASH FLOWS (UNAUDITED)

	Nine Months Ended September 30,
	2003			2002
Operating activities:
Net income	$	25,687,651		$	21,876,563
Adjustments to reconcile net income to cash flows:
Depreciation and amortization	24,125,184			21,930,861
Pension expense (income)	716,172			(2,686,336		)
Deferred income taxes, net	14,677,959			3,904,991
Investment tax credit, net	(450,014		)	(432,826		)
Issuance of common stock and stock options for incentive plans	984,473			791,594
Unrealized loss on derivatives	207,956			—
Cash flows impacted by changes in:
Accounts receivable and accrued unbilled revenues	(3,661,865		)	(8,299,515		)
Fuel, materials and supplies	1,830,108			218,607
Prepaid expenses and deferred charges	(1,998,134		)	(951,883		)
Accounts payable and accrued liabilities	(12,181,128		)	(7,219,787		)
Customer deposits, interest and taxes accrued	7,846,646			18,073,077
Other liabilities and other deferred credits	779,611			1,435,953
Accumulated provision - rate refunds	(18,718,679		)	13,783,835

Net cash provided by operating activities	39,845,940			62,425,134

Investing activities:
Capital expenditures – regulated	(51,926,445		)	(52,900,347		)
Capital expenditures and other investments - non-regulated	(3,305,051		)	(3,644,196		)

Net cash used in investing activities	(55,231,496		)	(56,544,543		)

Financing activities:
Proceeds from issuance of common stock	4,887,466			55,540,308
Proceeds from issuance of senior notes	98,000,000			—
Net (repayments) proceeds from short-term borrowings	36,459,000			(4,544,320		)
Long-term debt issuance costs	(3,679,752		)	—
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	—			(2,517,371		)
Dividends	(21,816,801		)	(20,675,335		)
Redemption of First Mortgage Bonds				(37,578,000		)
Other	82,096			(3,705		)

Net cash provided by (used in) financing activities	4,265,921			(9,778,423		)

Net (decrease) in cash and cash equivalents	(11,119,635		)	(3,897,832		)

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

Cash and cash equivalents at end of period	$	3,319,592		$	7,542,443

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.

Note 2 - 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 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 in the first quarter of 2003, we recorded a non-recurring discounted liability and a regulatory asset of approximately $630,000 because we expect to recover these costs of removal in electric rates. This liability will be accreted over the period up to the estimated settlement date. The balance at the end of the third quarter of 2003 was approximately $648,000. At September 30, 2003, also pursuant to FAS 143, we reclassified approximately $4.0 million of the estimated cost of dismantling and removing plant from service upon retirement from accumulated depreciation to a regulatory liability. This balance sheet reclassification had no impact on results of operations. This estimated liability may be subject to further refinement pending the results of our depreciation study expected to be completed in the fourth quarter of 2003.

In December 2002, the FASB issued SFAS No. 148 (FAS 148), “Accounting for Stock-Based Compensation-Transition and Disclosure”. 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. The adoption of FAS 149 did not have a material impact on our financial condition and results of operations.

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. We adopted the required provisions of FAS 150 on July 1, 2003 and the adoption did not materially impact our financial statements.

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 rescission 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 50.01% guarantee by our wholly-owned subsidiary, EDE Holdings, Inc., of a

$2.4 million note issued by Mid-America Precision Products, LLC (MAPP), we do not have any material commitments within the scope of FIN 45.

In January 2003, the FASB issued FASB Interpretation No. 46 (FIN 46), “Consolidation of Variable Interest Entities, an interpretation of ARB 51”. The primary objectives of FIN 46 are to provide guidance on the identification of entities for which control is achieved through means other than through voting rights (“variable interest entities” or “VIEs”) and how to determine when and which business enterprise should consolidate the VIE (the “primary beneficiary”). We are evaluating the impact of FIN 46 but do not at present believe we are the primary beneficiary of any VIEs. FIN 46 will be effective for us beginning in the quarter ending December 31, 2003.

Note 3 – Risk Management and Derivative Financial Instruments

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

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), requires 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 as a cash-flow hedge are recorded in other comprehensive income, until earnings are affected by the variability of the hedged 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 September 30, 2003, we have recorded the following assets and liabilities representing the fair value of derivative financial instruments held as of that date and subject to the reporting requirements of FAS 133.

Current assets	$	10,317,093	Current liabilities	$	20,550

Noncurrent assets	$	16,972,150	Noncurrent liabilities	$	14,192,916

A $7,608,760 net of tax, unrealized gain representing the fair market value of these contracts is recognized as Accumulated Other Comprehensive Income in the capitalization section of the balance sheet. The tax effect of $4,663,433 on this gain is included in deferred taxes. These amounts will be adjusted cumulatively on a monthly basis during the determination periods beginning October 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 or interest expense, as applicable.

In the first quarter of 2003, we began recording unrealized gains/(losses) 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 gas 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/(losses), which were not material in the prior periods ended September 30, 2002, in “Other - net” under the Other Income and Deductions section. Gains/(losses) from the ineffective (overhedged) portion of our hedging activities included in “Fuel” were $(36,000) (pre-tax) for the quarter ended September 30, 2003, $2.3 million (pre-tax) for the nine months ended September 30, 2003 and $3.6 million (pre-tax) for the twelve months ended September 30, 2003. See Note 4 – Long-Term Debt (below) for information on our hedging of interest rates.

We have also entered into fixed-price forward physical contracts for the purchase of natural gas, coal and purchased power. These contracts are not subject to the fair value accounting of FAS 133 because they are considered to be normal purchases and normal sales (NPNS). None of our NPNS contracts contain a price adjustment feature as contemplated in Derivative Implementation Group Issue No. C20 issued in June 2003 and effective the first fiscal quarter beginning after July 10, 2003. We have instituted a process to determine if any future executed contracts that otherwise qualify for the NPNS exception contain a price adjustment feature and will account for these contracts accordingly.

Note 4 – Long-Term Debt

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 September 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 September 30, 2003. However, $59 million of the facility as of that date was used to back up our commercial paper and was not available to be borrowed.

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 were capitalized as a financing fee and will be 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.

Bonds, 7% Series due 2023 for approximately $46.8 million, including interest. The $1.7 million aggregate redemption premiums paid in connection with the redemption of these first mortgage bonds, together with $1.1 million of remaining unamortized issuance costs and discounts on the redeemed first mortgage bonds, will be recorded as a regulatory asset and amortized as interest expense over the life of the 2033 Notes. On May 16, 2003, we entered into an interest rate derivative contract with an outside counterparty to hedge against the risk of a rise in interest rates impacting the 2033 Notes prior to their issue. We “marked-to-market” the fair market value of this contract at the end of each accounting period as specified in FAS 133 and FAS 149. The fair market value of this contract at September 30, 2003 was $1.9 million net of tax and is included in Other Comprehensive Income. The before tax balance of $3.0 million is included in the Unrealized Gain in Fair Value of Derivatives Contracts — Current balance on our Consolidated Balance Sheet. Upon issuance of the 2033 Notes, the realized gain of $5.1 million from the derivative contract was recorded as a regulatory liability and will be amortized over the life of the debt to reduce interest expense.

Note 5 – 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 was 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, which we disputed. We terminated the agreement effective December 3, 2001 as a result of, among other reasons, the drop in Enron’s credit ratings. In October 2003, we reached an agreement with Enron to settle the dispute for a payment of $1.0 million. This settlement agreement was approved by the bankruptcy court. On October 27, 2003, Enron signed the settlement agreement and we paid the $1 million on October 29, 2003. We accrued the $1.0 million as a charge to fuel expense in the third quarter of 2003.

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 acturial assumptions. At December 31, 2002, there was no minimum pension liability required to be recorded.

Our net periodic benefit (cost) or income (related to the application of FAS 87), net of tax, is presented below as a percentage of net income for each of the periods ended September 30, 2003 and 2002:

	% Effect on Net Income
	2003		2002
Three Months Ended	(0.10	)%	2.25	%
Nine Months Ended	(1.30	)%	5.68	%
Twelve Months Ended	0.25	%	8.77	%

Note 6 – Regulatory Matters

All of our regulatory assets are earning a current return except for approximately $9.5 million related to premiums and related costs for any debt reacquired since the latest rate case in each jurisdiction. Cost recovery of debt costs has historically been allowed in our rate cases. We don’t expect a change in this regulatory practice in our next rate case.

Note 7 – Accounts Receivable - Other

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

	September 30, 2003		December 31, 2002
Accounts receivable for meter loops, meter bases, line extensions, highway projects, etc.	$	2.2	$	2.2
Accounts receivable due to our non-regulated subsidiary companies	1.9		3.0
Accounts receivable from Westar Generating, Inc. for commonly-owned facility	1.0		1.5
Taxes receivable – overpayment of estimated income taxes	—		2.8
Accounts receivable for true-up on maintenance contracts	3.6		—
Other	0.5		0.5
Total accounts receivable - other	$	9.2	$	10.0

The $3.6 million in accounts receivable for true-up on maintenance contracts primarily represents the gross amount of a 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 (SLCC). Monthly payments on this contract have been based on an estimated number of starts. Actual starts during the twelve month period ended June 30, 2003, however, were significantly less than originally estimated resulting in the June 2003 true up credit. 40% of this credit belongs to Westar Generating, Inc., the owner of 40% of the SLCC, and has been recorded in accounts payable as of September 30, 2003. The remainder of this account represents the quarterly estimated credits earned this year.

Note 8 - Regulated - Other Operating Expense

The following table sets forth the major components comprising “regulated – other” under “Operating Revenue Deductions” on our consolidated statements of income (in millions) for all periods presented:

	Third Quarter 2003		Third Quarter 2002			9 Months Ended 2003		9 Months Ended 2002			12 Months Ended 2003		12 Months Ended 2002
Transmission and distribution expense	$	2.1	$	2.0		$	6.2	$	6.6		$	8.2	$	8.4
Power operation expense (other than fuel)	2.5		2.2			6.9		6.5			9.3		8.4
Customer accounts & assistance expense	1.7		1.6			4.9		5.1			6.6		6.7
Employee pension expense (income)	0.2		(0.5		)	1.0		(1.9		)	0.7		(2.9		)
Employee healthcare plan	1.7		1.7			5.0		4.8			6.5		5.9
General office supplies and expense	1.6		1.5			4.6		4.4			6.2		6.0
Administrative and general expense	2.0		1.7			6.2		5.2			8.0		6.5
Allowance for uncollectible accounts	0.2		0.4			0.7		0.9			1.0		2.0
Miscellaneous expense	—		0.1			—		0.3			0.1		0.5
Total	$	12.0	$	10.7		$	35.5	$	31.9		$	46.6	$	41.5

Note 9 – Stock Options

We have a 1996 Stock Incentive Plan (the Plan), which provides for the grant of up to 650,000 shares of common stock through January 2006. Prior to 2002, no options had been granted under the Plan. During 2003 and 2002, options consisting of the right to purchase 49,200 and 69,700 shares, respectively, of common stock were issued under the Plan to qualified individuals. The options were issued with an exercise price equal to the fair market value of the shares on the date of grant, become exercisable after three years and expire ten years after the date granted. A total of 531,100 shares remained available for grant at September 30, 2003.

We utilize the accounting provision of FAS 123 “Accounting for Stock-Based Compensation” and recognize compensation expense over the vesting period of stock-based compensation awards based upon the fair-value of the award as of the date of issuance.

Presented below is a summary of stock option plan activity for the years shown:

For Year Ended:	Options Granted	Weighted Avg. Exercise Price		Fair Value Per Option		Expiration Date	Total Fair Value
December 31, 2002	69,700	$	20.95	$	5.05	01/31/2012	$	351,985
September 30, 2003*	49,200	$	18.25	$	4.99	02/06/2013	$	245,508
Total	118,900	$	19.83

*Nine months ended

We recognized $0.2 million and $0.1 million in compensation expense for the nine month periods ended September 30, 2003 and 2002, respectively.

Note 10 - - Non-regulated Businesses

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

In September 2003, EDE Holdings, Inc. purchased an approximate 6% interest in ETG, a company that makes automated meter reading equipment. This investment is accounted for under the cost method.

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.” 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.

	For the quarter ended September 30,
	2003					2002
	Non-Regulated			Total Company		Non-Regulated			Total Company

Statement of Income Information
Revenues	$	5,005,329	*	$	101,029,025	$	3,858,777		$	99,823,415
Operating income (loss)	$	(341,843	)	$	24,620,611	$	1,607		$	26,061,015
Net income (loss)	$	(501,809	)	$	16,762,645	$	(70,754	)	$	18,386,592
Minority interest	$	135,266		$	135,266	$	111,708		$	111,708

Capital Expenditures
	$	812,073		$	8,693,635	$	3,349,941		$	23,256,557

	For the nine months ended September 30,
	2003**					2002
	Non-Regulated			Total Company		Non-Regulated			Total Company

Statement of Income Information
Revenues	$	15,348,617	*	$	252,537,686	$	4,813,185		$	234,024,739
Operating income (loss)	$	(944,015	)	$	50,140,614	$	(728,536	)	$	45,685,193
Net income (loss)	$	(1,392,739	)	$	25,687,651	$	(797,683	)	$	21,876,563
Minority interest	$	441,031		$	441,031	$	111,708		$	111,708

Capital Expenditures
	$	3,552,580		$	54,385,007	$	5,263,423		$	57,132,814

	As of September 30, 2003					As of December 31, 2002
	Non-Regulated			Total Company		Non-Regulated			Total Company

Balance Sheet Information
Total assets	$	23,537,991		$	1,015,865,786	$	21,952,605		$	970,153,423
Minority interest	$	1,247,350		$	1,247,350	$	806,319		$	806,319

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

**Increases in non-regulated revenues and minority interest for the nine months ended September 30, 2003 primarily reflect the acquisition of MAPP in July 2002, a company specializing in close tolerance custom manufacturing for the aerospace, electronics, telecommunications and machinery industries.

FORWARD LOOKING STATEMENTS

Certain matters discussed in this quarterly report are “forward-looking statements” intended to qualify for the safe harbor from liability established by the Private Securities Litigation Reform Act of 1995. Such statements address or may address future plans, objectives, expectations and events or conditions concerning various matters such as capital expenditures, earnings, pension and other costs, competition, litigation, our construction program, our financing plans, rate and other regulatory matters, liquidity and capital resources, and accounting matters. Forward-looking statements may contain words like “anticipate,” “believe,” “expect,” “project,” “objective” or similar expressions to identify them as forward-looking statements. Factors that could cause actual results to differ materially from those currently anticipated in such statements include: the amount, terms and timing of rate relief we seek and related matters; the cost and availability of purchased power and fuel, and the results of our activities (such as hedging) to reduce the volatility of such costs; electric utility restructuring, including ongoing state and federal activities; weather, business and economic conditions and other factors which may impact customer growth; operation of our generation facilities; legislation; regulation, including environmental regulation (such as NOx regulation); competition; the impact of deregulation on off-system sales; changes in accounting requirements; other circumstances affecting anticipated rates, revenues and costs, including matters such as the effect of changes in credit ratings on the availability and our cost of funds; the revision of our construction plans and cost estimates; the performance of our non-regulated businesses; the success

of efforts to invest in and develop new opportunities; and costs and 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.

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

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

RESULTS OF OPERATIONS

The following discussion analyzes significant changes in the results of operations for the three-month, nine-month and twelve-month periods ended September 30, 2003, compared to the same periods ended September 30, 2002.

Electric Operating Revenues and Kilowatt-Hour Sales

Of our total electric operating revenues during the third quarter of 2003 approximately 43% were from residential customers, 31% from commercial customers, 16% from industrial customers, 4% from wholesale on-system customers, 2% from wholesale off-system transactions and 4% from miscellaneous sources, primarily transmission services.

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

	Kwh Sales (in millions)
	Third Quarter 2003	Third Quarter 2002	%* Change		9 MOE 2003	9 MOE 2002	%* Change		12 MOE 2003	12 MOE 2002	%* Change
Residential	507.5	511.8	(0.8	)%	1,341.4	1,332.9	0.6	%	1,734.9	1,685.0	3.0	%
Commercial	394.1	398.9	(1.2	)	1,049.4	1,049.8	0.0		1,377.8	1,385.8	(0.6	)
Industrial	284.6	271.0	5.0		786.3	769.2	2.2		1,044.6	1,009.5	3.5
Wholesale On-System	87.8	93.8	(6.4	)	238.3	248.3	(4.1	)	313.0	320.7	(2.4	)
Other***	28.0	26.9	3.8		78.4	77.4	(1.4	)	103.9	101.5	2.4
Total On-System	1,302.0	1,302.4	0.0		3,493.8	3,477.6	0.5		4,574.2	4,502.5	1.6

	Operating Revenues ($ in millions)
	Third Quarter 2003		Third** Quarter 2002		%* Change		9 MOE 2003		9 MOE** 2002		%* Change		12 MOE** 2003		12 MOE** 2002		%* Change
Residential	$	40.8	$	40.0	2.0	%	$	98.1	$	93.3	5.0	%	$	124.3	$	118.0	5.3	%
Commercial	29.4		28.8		2.1		70.0		66.9		4.7		88.6		86.7		2.3
Industrial	15.5		14.1		10.4		38.6		35.7		8.1		49.7		46.2		7.5
Wholesale On-System	3.8		3.5		8.9		9.6		9.3		3.8		12.2		12.1		0.6
Other***	2.2		2.0		10.8		5.6		5.2		7.8		7.2		6.7		7.7
Total On-System	$	91.7	$	88.4	3.8		$	221.9	$	210.4	5.5		$	282.0	$	269.7	4.6

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

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

***Other Kwh sales and Other Operating Revenues include street lighting, other public authorities and interdepartmental usage.

On-System Transactions

Kwh sales for our on-system customers were virtually the same overall during the third quarter of 2003 as in the third quarter of 2002 (despite the setting of five new peaks in the third quarter of 2003) with variances only within the major customer classes. We set a new peak demand of 1041 megawatts on August 25, 2003. Total cooling degree days (the number of degrees that the average temperature for that period was above 65° F) for July and August of 2003 were 14.7% more than the 20-year average and 13.1% more than the same period last year while total cooling degree days for September 2003 were 42.1% less than the 20-year average and 56.0% less when compared to the same month last year. Despite the overall flat Kwh sales, revenues for our on-system customers increased approximately $3 million as a result of the Missouri, Oklahoma and FERC rate increases discussed below. An approximate $2 million increase in revenues attributed to customer growth was more than offset by negative weather, reflecting the mild September temperatures described above.

Although, residential and commercial Kwh sales decreased during the third quarter of 2003 compared to the third quarter of 2002 due mainly to the milder temperatures in September 2003, related revenues increased as a result of the December 2002 Missouri rate increase and, to a lesser extent, the August 2003 Oklahoma rate increase discussed below.

Industrial Kwh sales, which are not particularly weather sensitive, increased during the third quarter of 2003 as compared to the same period last year due to increased sales resulting mainly from the addition of two new oil pipeline pumping stations on our system that became fully operational in June 2003. Industrial revenues increased as a result of the increased sales as well as the December 2002 Missouri rate increase and, to a lesser extent, the August 2003 Oklahoma rate increase.

On-system wholesale Kwh sales decreased during the third quarter of 2003 due mainly to the change in customer status in June 2003 of an on-system wholesale customer/aggregator, comprising three of our on-system wholesale accounts, which elected to go off-system and purchase power from us at market-based rates. Revenues received from these accounts, which comprised 5-6% of our on-system wholesale sales, but less than one-half percent of our total on-system sales, in both 2002 and 2001, are now included in our off-system sales. Overall revenues associated with these FERC-regulated sales increased as a result of the FERC rate increase that became effective May 1, 2003 and as a result of the fuel adjustment clause applicable to such sales. This clause permits the pass through to customers of changes in fuel and purchased power costs.

For the nine months ended September 30, 2003, Kwh sales to our residential customers increased slightly as compared to the same period last year while commercial sales were virtually the same as last year. Increased sales reflecting the colder temperatures in the first quarter of 2003 were offset by decreased sales in the second and third quarters of 2003 reflecting the milder temperatures during June and September. Residential and commercial revenues increased during the nine months ended September 30, 2003 primarily reflecting the December 2002 Missouri rate increase and, to a lesser extent, the August 2003 Oklahoma rate increase. Industrial Kwh sales and related revenues increased during the nine months ended September 30, 2003, reflecting the addition of the two new oil pipeline pumping stations in June 2003 as well as better economic conditions in the first quarter of 2003 as compared to the first quarter of 2002 during which our service territory experienced a general slowdown in economic activity. Industrial revenues were also enhanced by the Missouri and Oklahoma rate increases. On-system wholesale Kwh sales decreased for the nine months ended September 30, 2003 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 and the operation of the fuel adjustment clause applicable to such sales. Overall, the Missouri, Oklahoma and FERC rate increases contributed approximately $10 million to the increased revenues for the nine months ended September 30, 2003 with the remainder of the increase being related to customer growth, offset by unfavorable weather.

For the twelve months ended September 30, 2003, Kwh sales to our residential customers increased reflecting cooler temperatures during the fourth quarter of 2002 while sales to our commercial customers decreased slightly.Residential and commercial revenues increased during the twelve months ended September 30, 2003, primarily reflecting the December 2002 Missouri rate increase and August 2003 Oklahoma rate increase. Industrial sales increased during the twelve-month period reflecting the two new oil pipeline pumping stations in June 2003 as well as the better economic conditions discussed above. Related revenues increased reflecting the Missouri and Oklahoma rate increases. On-system wholesale Kwh sales decreased for the twelve months ended September 30, 2003, reflecting the change in customer status of one of our on-system customers to off-system as discussed above. Revenues associated with these FERC-regulated sales increased reflecting the FERC rate increase. Overall, the Missouri, Oklahoma and FERC rate increases contributed approximately $11 million to the increased revenues for the twelve months ended September 30, 2003 with the remainder being related to customer growth and weather having a slight negative effect.

Rate Matters

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

Jurisdiction	Date Requested	Annual Increase Granted		Percent Increase Granted		Date Effective
Missouri - Electric	November 3, 2000	$	17,100,000	8.40	%	October 2, 2001
Missouri - Electric	March 8, 2002	11,000,000		4.97	%	December 1, 2002
Missouri - Water	May 15, 2002	358,000		33.70	%	December 23, 2002
Kansas - Electric	December 28, 2001	2,539,000		17.87	%	July 1, 2002
FERC -Electric	March 17, 2003	1,672,000		14.00	%	May 1, 2003
Oklahoma -Electric	March 4, 2003	766,500		10.99	%	August 1, 2003

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

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 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)	Third Quarter		Nine Months Ended		Twelve Months Ended		Third Quarter		Nine Months Ended		Twelve Months Ended
Revenues	$	3.5	$	13.1	$	18.6	$	6.7	$	16.4	$	18.3
Expenses	2.2		8.4		11.6		3.6		10.3		11.0
Net	$	1.3	$	4.7	$	7.0	$	3.1	$	6.1	$	7.3

The decrease in revenues less expenses for all periods presented resulted primarily from the non-renewal of short-term contracts for firm energy that ran from January 2002 through June 2003. We sold this energy in the wholesale market when it was not required to meet our own customers’ needs during that period. The reduction in off-system sales for the third quarter of 2003 as compared to the same period last year was also due to the less favorable weather discussed above.

We, and most other electric utilities with interstate transmission facilities, have placed our facilities 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, 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 reached a settlement with KCP&L to pay the amount we had been accruing since October 2002, which was approximately $0.8 million as of the settlement date and was paid in August 2003, 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. On October 15, 2003, the SPP announced it had filed with the FERC seeking formal recognition as an RTO in accordance with FERC Order 2000. On October 27, 2003 we filed a notice with the SPP for the right to withdraw from the SPP effective October 31, 2004 for the following reasons: uncertainty surrounding the treatment from the states regarding RTO participation and cost recovery; increased risk of additional membership assessment cost allocation due to potential member departures; and anticipated change in the terms and conditions of the SPP tariff and network services. Such withdrawal would require approval from the FERC. We retain the option, however, to rescind such notice on or before October 31, 2004 and remain a member of the SPP. 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 at this time.

Operating Revenue Deductions

During the third quarter of 2003, total operating revenue deductions increased approximately $2.6 million (3.6%) compared with the same period last year. Total fuel costs increased approximately $3.5 million (20.5%) during the third quarter of 2003 as compared to the same period in 2002, primarily reflecting a $1 million accrual during the third quarter of 2003 for the payment to be made by us in the fourth quarter of 2003 pursuant to a settlement with Enron of a fuel contract dispute (See Item 5 — Other Information), a $0.7 million coal inventory adjustment in August and higher prices for the unhedged portion of the natural gas that we burned in our gas-fired units. Purchased power costs decreased approximately $2.4 million (15.5%) during the period primarily reflecting a shift from serving our energy needs with purchased power to generating our own power reflecting that it was more economical to run our own generating units during the third quarter of 2003 than to purchase power. This decrease in purchased power costs also reflects the non-renewal of the short-term contracts for firm energy that ran from January 2002 through June 2003. The net increase in fuel and purchased power during the third quarter of 2003 as compared to the same period last year was $1.1 million (3.3%).

Regulated – other operating expenses increased approximately $1.3 million (12.0%) during the third quarter of 2003 as compared to the same period in 2002. Employee pension expense contributed $0.7 million to this increase primarily due to a decline in the value of invested funds. See Note 5 – Commitments and Contingencies under Notes to Consolidated Financial Statements

(Unaudited) for information concerning the percentage of our net income that comprises our net periodic benefit cost related to the application of FAS 87.

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

Maintenance and repairs expense decreased approximately $1.3 million (22.0%) during the third quarter of 2003 as compared to the same period in 2002 reflecting, in part, a $0.5 million payment per contract terms, to Westar Generating, Inc. (WGI) for maintenance expense related to our usage of the existing Unit No. 2 turbine prior to WGI’s 40% joint ownership of the State Line Combined Cycle Unit. Depreciation and amortization expense increased approximately $0.8 million (11.6%) during the quarter due to increased plant in service. Although our effective tax rate was the same for both periods, total income taxes decreased approximately $0.5 million (5.7%) due primarily to a decrease in taxable income. Other taxes increased $0.1 million (2.7%) during the period due mainly to increased property taxes reflecting our additions to plant in service.

For the nine months ended September 30, 2003, total operating revenue deductions increased approximately $14.1 million (7.5%). Purchased power costs increased approximately $1.9 million (4.2%) reflecting 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 to our facilities. Also contributing to the increase in purchased power costs were the short-term contracts for firm energy that ran from January 2002 through June 2003. Total fuel costs decreased approximately $0.7 million (1.6%) during the period primarily reflecting $4.6 million of net gains recognized in the first quarter of 2003, offsetting the $3.5 million increase in fuel costs during the third quarter of 2003. The $4.6 million of net gains recognized in the first quarter of 2003 was in relation to (1) the expiration of natural gas derivative contracts occurring during the normal course of business in the first quarter of 2003 ($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 3 — Risk Management and Derivative Financial Instruments under Notes to Consolidated Financial Statements (Unaudited). The net increase in fuel and purchased power for the nine months ended September 30, 2003 was $1.2 million (1.4%).

Regulated – other operating expenses increased approximately $3.6 million (11.1%) for the nine months ended September 30, 2003. Employee pension expense contributed $2.9 million to this increase primarily due to a decline in the value of invested funds. See Note 5 – Commitments and Contingencies under Notes to Consolidated Financial Statements (Unaudited) for information concerning the percentage of our net income that comprises our net periodic benefit cost related to the application of FAS 87. Administrative and general expense increased approximately $1.0 million due mainly to increases in property insurance, outside services and regulatory commission expenses related to our recent rate cases.

Maintenance and repairs expense decreased $3.7 million (20.1%) for the nine months ended September 30, 2003 reflecting the $0.5 million payment made to WGI during the third quarter of 2002 discussed above and 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 twelve month period ended June 30, 2003, however, were significantly less than originally estimated resulting in the June 2003 true up credit. 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 of approximately $1.1 million 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 $1.8 million (9.3%) during the nine-month period reflecting increased plant in service. Although our effective tax rate was the same for both periods, total provisions for income taxes increased $2.5 million (22.1%) for the nine months ended September 30, 2003 due primarily to an increase in taxable income. Other taxes increased $0.2 million (1.4%) during the period primarily due to increased property taxes reflecting our additions to plant in service discussed above.

During the twelve months ended September 30, 2003, total operating revenue deductions increased approximately $21.3 million (8.8%) compared to the same period in 2002. Total purchased power costs increased approximately $5.9 million (10.1%) offset by a decrease in total fuel costs of approximately $6.4 million (11.6%). Purchased power costs increased primarily due to increased demand because of weather conditions in the first quarter of 2003, higher purchased power costs in the first quarter of 2003, our inability at times during extremely cold weather to get natural gas delivered to our facilities, and the term purchases of firm energy from the short-term energy contracts that ran through June 2003. Total fuel costs decreased during the twelve months ended September 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 and less generation by our gas-fired units due in large part to the term purchases of firm energy.

Regulated – other operating expenses increased approximately $5.1 million (12.2%) during the twelve months ended September 30, 2003, compared to the same period in 2002. Employee pension expense contributed $3.6 million to this increase due primarily to a decline in the value of invested funds. See Note 5 – Commitments and Contingencies under Notes to Consolidated Financial Statements (Unaudited) for information concerning the percentage of our net income that comprises our net periodic benefit cost related to the application of FAS 87. Administrative and general expense increased approximately $1.5 million due mainly to increases in property insurance, outside services and regulatory commission expenses related to our recent rate cases. Allowance for doubtful accounts decreased $1.0 million due to improved collection processes for overdue accounts in 2003.

Maintenance and repairs expense decreased approximately $5.1 million (19.8%) during the twelve months ended September 30, 2003 compared to the same period in 2002 primarily reflecting the $1.8 million true-up credit from Siemens Westinghouse in June 2003 and lower payments during the first half of 2003 on our long-term operating plant maintenance contracts as discussed above. Depreciation and amortization expense increased approximately $1.5 million (5.8%) due to increased levels of plant and equipment. Total provision for income taxes increased $4.8 million (43.3%) due primarily to higher taxable income during the current period. Our effective federal and state income tax rate for the twelve months ended September 30, 2003 was 34.8% as compared to 33.7% for the twelve months ended September 30, 2002. Other taxes increased approximately $1.5 million (10.1%) due mainly to increased property taxes.

Non-regulated Items

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 (MAPP), customer information system software services and other energy services through our wholly owned subsidiary, EDE Holdings, Inc. In September, 2003, EDE Holdings, Inc. purchased an approximate 6% interest in ETG, a company that makes automated meter reading equipment.

During the third quarter of 2003, total non-regulated operating revenue increased approximately $1.0 million while total non-regulated operating expense increased approximately $1.3 million as compared with the same period in 2002. For the nine months ended September 30, 2003, total non-regulated operating revenue increased approximately $10.3 million while total non-regulated

operating expense increased approximately $10.0 million as compared to the same period in 2002. For the twelve-months ended September 30, 2003, total non-regulated operating revenue increased approximately $15.4 million while total non-regulated operating expense increased approximately $15.7 million. The significant increases in both revenues and expenses for the nine and twelve-month-ended periods were primarily due to the acquisition of MAPP in July 2002. The increase in expenses for all periods presented was also due to the activities of Conversant, Inc., a software company which began business in early 2002. In June 2003, Conversant, Inc. signed a contract with a prospective customer, Intermountain Gas Company of Boise, Idaho. A pilot project has been successfully completed and Conversant, Inc. will begin contributing license revenues in the fourth quarter of 2003.

Our non-regulated businesses generated a $0.5 million net loss in the third quarter of 2003 as compared to a $0.1 million net loss in the third quarter of 2002, a net loss of $1.4 million for the nine months ended September 30, 2003 as compared to a net loss of $0.8 million for the same period during 2002 and a net loss of $2.1 million for the twelve months ended September 30, 2003 as compared to a net loss of $1.0 million for the twelve months ended September 30, 2002. The increase in net loss for all three periods presented was due primarily to the results of Conversant, Inc.

Nonoperating Items

Total interest charges on long-term debt increased $0.4 million (7.0%) during the third quarter of 2003, $0.8 million (4.2%) during the nine months ended period and $0.1 million (0.5%) during the twelve months ended September 30, 2003, reflecting the sale of $50 million of 7.05% senior notes on December 23, 2002, the sale of $98 million of 4.5% senior notes on June 17, 2003 and the redemption of all $100 million aggregate principal amount of our Senior Notes, 7.70% Series due 2004 on June 19, 2003.

Other Comprehensive Income

The change in the fair market value of open contracts related to our gas procurement program, our interest rate derivative contracts 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, or interest expense, as applicable, in the periods in which they are actually realized or no longer qualify for hedge accounting. The $60 million 30-year interest rate derivative contract that we had entered into on May 16, 2003 expired on October 29, 2003 with a gain of $5.1 million. This amount will be recorded as a regulatory liability and amortized against interest expense over the 30 year life of the debt issue we had hedged. See Note 4 – Long Term Debt under Notes to Consolidated Financial Statements (Unaudited).

We had a net change in unrealized loss of $2.7 million for the third quarter of 2003 as compared to a net change in unrealized loss of $0.1 million for the third quarter of 2002, a net change in unrealized gain of $1.0 million for the nine months ended September 30, 2003 as compared to a net change in unrealized gain of $6.0 million for the nine months ended September 30, 2002 and a net change in unrealized gain of $3.2 million for the twelve months ended September 30, 2003 as compared to a net change in unrealized gain of $5.6 million for the twelve months ended September 30, 2002. These changes are the result of the marking to market of fuel derivative contracts with the remainder resulting from our interest rate derivative contracts. Our interest rate derivative contracts contributed a $1.4 million unrealized gain for the third quarter of 2003 and a $1.9 million unrealized

gain for both the nine months ended and twelve months ended periods in 2003. We had no interest rate derivative contracts in 2002.

Earnings

For the third quarter of 2003, basic and diluted earnings per weighted average share of common stock were $0.73 compared to $0.82 during the third quarter of 2002. Earnings per share were positively impacted by the December 2002 Missouri rate increase, May 2003 FERC rate increase and August 2003 Oklahoma rate increase and decreased maintenance and repairs expense. Earnings per share in the third quarter of 2003 were negatively impacted by less favorable weather, a $1.8 million decrease in the net impact (revenues less expenses) of off-system sales, a $1.1 million net increase in total fuel and purchased power costs, a $0.7 million net increase in pension expense, a $0.8 million increase in depreciation and amortization expense and a $0.5 million net loss from our non-regulated businesses as compared to a $0.1 million net loss during the same period last year.

Basic and diluted earnings per weighted average share of common stock for the nine months ended September 30, 2003, were $1.13 compared to $1.04 for the nine months ended a year earlier. Earnings per share were positively impacted by the Missouri, FERC and Oklahoma rate increases and decreased maintenance and repairs expense. Earnings per share for the nine months ended September 30, 2003 were negatively impacted by a $1.4 million decrease in the net impact (revenues less expenses) of off-system sales, a $1.2 million net increase in total fuel and purchased power costs, a $2.9 million net increase in pension expense, a $1.8 million increase in depreciation and amortization expense and a $1.4 million net loss from our non-regulated businesses as compared to a $0.8 million net loss during the same period last year.

For the twelve months ended September 30, 2003, basic and diluted earnings per weighted average share of common stock were $1.29 compared to $1.08 for the year earlier period. Earnings per share were positively impacted by the Missouri, FERC and Oklahoma rate increases as well as increased sales reflecting cooler temperatures during the fourth quarter of 2002. A decrease of $5.1 million in maintenance and repairs expense and a $0.5 million net decrease in fuel and purchase power costs also positively impacted earnings per share. Earnings per share for the twelve months ended September 30, 2003 were negatively impacted by a $3.6 million net increase in pension expense, a $1.5 million increase in depreciation expense, and a $2.1 million net loss from our non-regulated businesses as compared to a $1.0 million net loss during the same period last year.

LIQUIDITY AND CAPITAL RESOURCES

Our capital expenditures totaled $8.7 million during the third quarter of 2003, compared to $23.4 million for the same period in 2002. For the nine months ended September 30, 2003, capital expenditures totaled $54.4 million compared to $58.1 million for the same period in 2002. Capital expenditures, as used in this section, include AFUDC and exclude expenditures to retire assets.

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

	Quarter Ended September 30, 2003		Nine Months Ended September 30, 2003
	(in millions)		(in millions)
Distribution and transmission system additions	$	6.2	$	20.0
FT8 peaking units - Energy Center	—		20.4
Additions and replacements – Asbury, Iatan and Riverton	0.3		1.8
May tornado damage	0.7		6.4
Fiber optics (non-regulated)	0.7		1.9
Other non-regulated capital expenditures	0.1		1.7
Other	0.7		2.2
Total	$	8.7	$	54.4

For the third quarter of 2003, 100% of our capital expenditures were paid with internally generated funds (funds provided by operating activities less dividends paid). For the first nine months of 2003, approximately 32% of our capital expenditures were paid with internally generated funds. The remainder was satisfied from short-term borrowings and proceeds from our sales of common stock and unsecured Senior Notes discussed below.

We had estimated that our capital expenditures would 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. Capital expenditures have been higher than expected so far this year, primarily as a result of the May tornado damage. We estimate that capital expenditures for the fourth quarter of 2003 will be approximately $5.2 million.

Our net cash flows provided by operating activities decreased $25.2 million during the first nine months of 2003 as compared to the first nine 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. At September 30, 2002, we had collected $13.8 million of the IEC during the first nine months of 2002. This outflow of cash in 2003 was partially offset by a $3.8 million increase in net income and a $4.6 million increase due to changes in accounts receivable and accrued unbilled revenues during the first nine months of 2003, primarily due to increased sales in July and August of 2003. Deferred income taxes increased $10.8 million during the first nine months of 2003 as compared to the same period in 2002, primarily due to deferred taxes related to an additional first year depreciation allowance primarily for our FT8 peaking units and the deduction of the loss on reacquired debt (the unamortized issuance costs and discounts on the redeemed first mortgage bonds). Accounts payable and accrued liabilities decreased $7.6 million primarily due to the completion of payments on our FT8 peaking units while customer deposits, interest and taxes accrued decreased $10.2 million due to a decrease in income tax liability.

Our net cash flows used in investing activities decreased $1.3 million during the first nine months of 2003 as compared to the same period in 2002 reflecting the completion of the two FT8 peaking units at the Empire Energy Center in April 2003.

Our net cash flows provided by financing activities increased $14.0 million during the first nine months of 2003 as compared to 2002 due to a $98 million issuance of Senior Notes and a $41.0 million increase in short-term debt partially offset by $109.8 million in redemption costs related to the redemption in June 2003 of $100 million of our Senior Notes, 7.70% Series due 2004.

We currently do not expect internally generated funds to provide any of the funds required for our remaining 2003 capital expenditures. We expect to utilize short-term debt or the proceeds of sales of long-term debt or common stock (including common stock sold under our Employee Stock Purchase Plan, our Dividend Reinvestment and Stock Purchase Plan, and our 401(k) Plan and ESOP) to fund our remaining 2003 capital expenditures.

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 acturial assumptions. At December 31, 2002, there was no minimum pension liability required to be recorded.

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 have been capitalized as a financing fee and will be amortized over the life of the 2013 Notes, along with the $9.1 million redemption premium paid on the 2004 Senior Notes.

On November 3, 2003, we issued $62.0 million aggregate principal amount of Senior Notes, 6.70% Series due 2033 for net proceeds of approximately $61.0 million. We used the proceeds from this issuance, along with short-term debt, to redeem three separate series of our outstanding first mortgage bonds: (1) all $2.25 million aggregate principal amount of our First Mortgage Bonds, 9¾% Series due 2020 for approximately $2.4 million, including interest; (2) all $13.1 million aggregate principal amount of our First Mortgage Bonds, 7¼% Series due 2028 for approximately $13.7 million, including interest; and (3) all $45.0 million aggregate principal amount of our First Mortgage Bonds, 7% Series due 2023 for approximately $46.8 million, including interest. The $1.7 million aggregate redemption premiums paid in connection with the redemption of these first mortgage bonds, together with $1.1 million of remaining unamortized issuance costs and discounts on the redeemed first mortgage bonds, will be recorded as a regulatory asset and amortized as interest

expense over the life of the 2033 Notes. On May 16, 2003, we entered into an interest rate derivative contract with an outside counterparty to hedge against the risk of a rise in interest rates impacting the 2033 Notes prior to their issue. We “marked-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 September 30, 2003 was $1.9 million net of tax and is included in Other Comprehensive Income. The before tax balance of $3.0 million is included in the Unrealized Gain in Fair Value of Derivatives Contracts — Current balance on our Consolidated Balance Sheet. Upon issuance of the 2033 Notes, the realized gain of $5.1 million from the derivative contract was recorded as a regulatory liability and will be amortized over the life of the debt to reduce interest expense.

We have an effective shelf registration statement with the SEC under which approximately $138 million of our common stock, first mortgage bonds, unsecured debt securities and preference stock remain available for issuance.

On October 24, 2003, the Board of Directors authorized the sale of up to 2,300,000 newly-issued shares of our common stock to the public through an underwritten public offering. We anticipate that, subject to market and other conditions, the shares will be offered for sale later this year.

Our mortgage bond indenture contains a restriction on the payment of dividends. So long as any of the existing first mortgage bonds are outstanding, we will not declare or pay any dividends (other than dividends payable in shares of our common stock) or make any other distribution on, or purchase (other than with the proceeds of additional common stock financing) any shares of, our common stock if the cumulative aggregate amount thereof after August 31, 1944 (excluding the first quarterly dividend of $98,000) would exceed the earned surplus accumulated after August 31, 1944, or the date of succession in the event another corporation succeeds to our rights and liabilities by a merger or consolidation.

Restrictions in our mortgage bond indenture could also 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 September 30, 2003 would permit us to issue approximately $221.7 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 September 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 2 to the Financial Statements is incorporated herein by reference.

CONTRACTUAL OBLIGATIONS

Set forth below is information summarizing our contractual obligations as of September 30, 2003:

Payments Due by Period

(in millions)

			Less than				More than
Contractual Obligations	Total		1 Year		1-3 Years		3-5 Years		5 Years

Long-Term Debt (w/o discount)	$	356.5	$	60.3	$	10.0	$	—	$	286.2
Trust Preferred Securities	50.0		—		—		—		50.0
Capital Lease Obligations	0.5		0.2		0.3		—		—
Operating Lease Obligations	1.0		0.6		0.4		—		—
Purchase Obligations*	248.6		41.6		74.8		51.5		80.7
Other Long-Term Liabilities**	3.3		0.3		1.1		1.9		—

Total Contractual Obligations	$	659.9	$	103.0	$	86.6	$	53.4	$	416.9

*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 $2.4 million note included in this total amount.

OFF-BALANCE SHEET ARRANGEMENTS

We have no off-balance sheet arrangements that have or are reasonably likely to have a current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.

CRITICAL ACCOUNTING POLICIES

Preparation of the financial statements and related disclosures in compliance with generally accepted accounting principles requires the application of appropriate technical accounting rules and guidance, as well as the use of estimates. Our application of these policies involves judgments regarding many factors, which, in and of themselves, could materially impact the financial statements and disclosures. Refer to Management’s Discussion and Analysis of Financial Condition and Results

of Operations that is incorporated by reference from our 2002 Annual Report to Shareholders into our Annual Report on Form 10-K for the period ended December 31, 2002, for a discussion of our critical accounting policies.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

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

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 less than $250,000. 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.

As of October 20, 2003, 77% of our anticipated volume of natural gas usage for the remainder of year 2003 is hedged at an average price of $2.98 per Dekatherm (Dth). In addition, approximately 63% of our anticipated volume of natural gas usage for the year 2004 is hedged at an average price of $3.31 per Dth, approximately 34% of our anticipated volume of natural gas usage for the year 2005 is hedged at an average price of $4.12 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.

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 changes in our internal control over financial reporting identified in connection with the evaluation described above that occurred during the third quarter of 2003 that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.

PART II. OTHER INFORMATION

Item 5. Other Information.

At September 30, 2003, the Company’s ratio of earnings to fixed charges was 2.44x. 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.

(4) Securities Resolution No. 5 dated as of October 29, 2003 under the Indenture for Unsecured Securities, dated as of September 10, 1999 between Empire and Wells Fargo Bank Minnesota, N.A.

(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.*

(99) Opinion of Anderson, Byrd, Richeson, Flaherty & Henrichs regarding the legality of Empire’s Senior Notes, 6.70% Series due 2033. This exhibit is filed herewith pursuant to Item 601 of Regulation S-K under the Securities Act of 1933 in lieu of filing as an exhibit to Empire’s registration statement on Form S-3 (File No. 333-107687), and, as this quarterly report on Form 10-Q is incorporated by reference in such registration statement, is set forth in full in such registration statement.

* 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 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/ Gregory A. Knapp
		Gregory A. Knapp
		Vice President - Finance


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

November 10, 2003