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, 2004 or

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

	For the transition period from to .

Commission file number: 1-3368

THE EMPIRE DISTRICT ELECTRIC COMPANY

(Exact name of registrant as specified in its charter)

Kansas	44-0236370
(State of Incorporation)	(I.R.S. Employer Identification No.)

602 Joplin Street, Joplin, Missouri	64801
(Address of principal executive offices)	(zip code)

Registrant’s telephone number: (417) 625-5100

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No o

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

As of November 1, 2004, 25,624,057 shares of common stock were outstanding.

THE EMPIRE DISTRICT ELECTRIC COMPANY

INDEX

Part I -	Financial Information (Unaudited):

Item 1.	Consolidated Financial Statements:

	a.	Consolidated Statements of Income

	b.	Consolidated Statement of Comprehensive Income

	c.	Consolidated Balance Sheet

	d.	Consolidated Statement of Cash Flows

	e.	Notes to Consolidated Financial Statements

	Forward Looking Statements

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

	Executive Summary

	Results of Operations

	Liquidity and Capital Resources

	Contractual Obligations

	Off-Balance Sheet Arrangements

	Critical Accounting Policies

	Recently Issued Accounting Standards

Item 3.	Quantitative and Qualitative Disclosures About Market Risk

Item 4.	Controls and Procedures

Part II -	Other Information:

Item 1.	Legal Proceedings - (none)

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds - (none)

Item 3.	Defaults Upon Senior Securities - (none)

Item 4.	Submission of Matters to a Vote of Security Holders – (none)

Item 5.	Other Information

Item 6.	Exhibits

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,
	2004			2003

Operating revenues:
Electric	$	91,089,046		$	95,769,637
Water	357,683			378,036
Non-regulated	5,294,802			4,881,352
	96,741,531			101,029,025
Operating revenue deductions:
Fuel	17,615,547			20,480,833
Purchased power	11,834,945			13,166,031
Regulated – other (Note 8)	12,646,542			12,723,809
Non-regulated expenses	5,362,415			5,147,234
Maintenance and repairs	4,682,946			4,646,214
Depreciation and amortization	7,756,286			7,328,688
Provision for income taxes	8,348,187			8,817,468
Other taxes	4,821,916			4,562,845
	73,068,784			76,873,122

Operating income	23,672,747			24,155,903
Other income and deductions:
Allowance for equity funds used during construction	26,253			—
Interest income	27,751			9,146
Provision for other income taxes	37,845			42,141
Minority interest	(39,328		)	(135,266		)
Other non-operating income	—			43,171
Other non-operating expense	(198,960		)	(234,584		)
	(146,439		)	(275,392		)
Interest charges:
Long-term debt – other	6,158,455			6,245,316
Note payable to securitization trust (Note 2)	1,062,500			—
Trust preferred distributions by subsidiary holding solely parent debentures (Note 2)	—			1,062,500
Commercial paper	8,055			218,300
Allowance for borrowed funds used during construction	(22,803		)	(30,451		)
Other	85,003			86,909
	7,291,210			7,582,574
Net income applicable to common stock	$	16,235,098		$	16,297,937

Weighted average number of common shares outstanding - basic	25,539,226			22,826,643

Weighted average number of common shares outstanding - diluted	25,585,988			22,839,041

Earnings per weighted average share of common stock - basic	$	0.64		$	0.71

Earnings per weighted average share of common stock - diluted	$	0.63		$	0.71

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,
	2004				2003

Operating revenues:
Electric	$	234,236,973			$	236,384,426
Water	1,031,290				1,059,230
Non-regulated	16,007,652				15,094,030
	251,275,915				252,537,686
Operating revenue deductions:
Fuel	52,536,158				42,192,501
Purchased power	38,324,825				46,798,935
Regulated – other (Note 8)	39,058,498				37,121,840
Non-regulated expenses	16,356,216				15,715,543
Maintenance and repairs	15,926,967				14,766,366
Depreciation and amortization	22,949,839				21,310,943
Provision for income taxes	10,297,780				13,454,132
Other taxes	13,589,487				12,119,047
	209,039,770				203,479,307

Operating income	42,236,145				49,058,379
Other income and deductions:
Allowance for equity funds used during construction	53,985				—
Interest income	56,953				41,640
Provision for other income taxes	147,237				96,670
Minority interest	(106,869			)	(441,031		)
Other non-operating income	67,016				42,867
Other non-operating expense	(663,497			)	(610,551		)
	(445,175			)	(870,405		)
Interest charges:
Long-term debt - other	18,478,197				19,817,375
Note payable to securitization trust (Note 2)	3,187,500				—
Trust preferred distributions by subsidiary holding solely parent debentures (Note 2)	—				3,187,500
Commercial paper	19,854				466,371
Allowance for borrowed funds used during construction	(59,012			)	(323,965		)
Other	273,605				435,277
	21,900,144				23,582,558
Net income applicable to common stock	$		19,890,826		$	24,605,416

Weighted average number of common shares outstanding - basic	25,410,881				22,721,594

Weighted average number of common shares outstanding -diluted	25,460,967				22,726,674

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

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

Dividends per share of common stock	$		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,
	2004				2003

Operating revenues:
Electric	$	301,113,693			$	302,558,469
Water	1,360,892				1,321,099
Non-regulated	21,768,539				20,536,375
	324,243,124				324,415,943
Operating revenue deductions:
Fuel	62,681,018				49,081,804
Purchased power	51,734,636				64,636,827
Regulated – other (Note 8)	51,689,629				48,258,833
Non-regulated expenses	21,800,826				21,974,613
Maintenance and repairs	21,084,010				20,677,995
Depreciation and amortization	30,327,376				27,894,627
Provision for income taxes	12,595,647				15,340,520
Other taxes	17,717,697				16,340,633
	269,630,839				264,205,852

Operating income	54,612,285				60,210,091
Other income and deductions:
Allowance for equity funds used during construction	53,985				—
Interest income	72,324				58,268
Provision for other income taxes	300,567				264,235
Minority interest	(19,471			)	(471,785		)
Other non-operating income	77,006				117,014
Other non-operating expense	(913,345			)	(981,436		)
	(428,934			)	(1,013,704		)
Interest charges:
Long-term debt	24,705,510				25,746,994
Note payable to securitization trust (Note 2)	3,187,500				—
Trust preferred distributions by subsidiary holding solely parent debentures (Note 2)	1,062,500				4,250,000
Commercial paper	159,795				686,510
Allowance for borrowed funds used during construction	(17,315			)	(502,032		)
Other	349,643				761,945
	29,447,633				30,943,417
Net income applicable to common stock	$	24,735,718			$	28,252,970

Weighted average number of common shares outstanding - basic	24,858,904				22,674,485

Weighted average number of common shares outstanding -diluted	24,909,921				22,677,483

Earnings per weighted average share of common stock -basic	$		1.00		$	1.25

Earnings per weighted average share of common stock – diluted	$		0.99		$	1.25

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,
	2004			2003

Net income	$	16,235,098		$	16,297,937

Reclassification adjustments for gains included in net income or reclassified to regulatory asset or liability (Notes 3 and 4)	(3,980,080		)	(2,546,123		)
Change in fair market value of open derivative contracts for period	4,088,150			(1,737,522		)
Income taxes	(41,066		)	1,627,786
Net change in unrealized gain on derivative contracts	67,004			(2,655,859		)

Comprehensive Income	$	16,302,102		$	13,642,078

	Nine Months Ended September 30,
	2004			2003

Net income	$	19,890,826		$	24,605,416

Reclassification adjustments for gains included in net income or reclassified to regulatory asset or liability (Notes 3 and 4)	(9,198,210		)	(5,954,743		)
Change in fair market value of open derivative contracts for period	7,673,380			7,511,667
Income taxes	579,436			(591,630		)
Net change in unrealized gain on derivative contracts	(945,394		)	965,294

Comprehensive Income	$	18,945,432		$	25,570,710

	Twelve Months Ended September 30,
	2004			2003

Net income	$	24,735,718		$	28,252,970

Reclassification adjustments for gains included in net income or reclassified to regulatory asset or liability (Notes 3 and 4)	(14,995,717		)	(5,907,293		)
Change in fair market value of open derivative contracts for period	12,928,864			11,029,665
Income taxes	785,404			(1,946,501		)
Net change in unrealized gain on derivative contracts	(1,281,449		)	3,175,871

Comprehensive Income	$	23,454,269		$	31,428,841

See accompanying Notes to Financial Statements

THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEET (UNAUDITED)

	September 30, 2004			December 31, 2003
ASSETS
Plant and property, at original cost:
Electric	$	1,216,335,172		$	1,191,445,355
Water	9,177,167			8,801,483
Non-regulated	23,141,245			21,105,515
Construction work in progress	6,406,002			5,840,870
	1,255,059,586			1,227,193,223
Accumulated depreciation and amortization	417,341,840			393,321,174
	837,717,746			833,872,049
Current assets:
Cash and cash equivalents	12,640,586			13,108,197
Accounts receivable - trade, net	26,801,892			21,946,990
Accrued unbilled revenues	6,809,982			7,784,403
Accounts receivable – other (Note 7)	10,428,821			9,243,073
Fuel, materials and supplies	30,989,153			29,179,937
Unrealized gain in fair value of derivative contracts (Note 3)	7,097,900			11,631,350
Prepaid expenses	2,891,371			2,240,748
	97,659,705			95,134,698
Deferred charges:
Regulatory assets (Notes 4 and 6)	54,280,689			55,977,495
Unamortized debt issuance costs	5,973,242			6,289,783
Unrealized gain in fair value of derivative contracts (Note 3)	4,192,150			567,000
Prepaid pension asset	14,448,107			16,359,920
Other	2,556,405			2,631,587
	81,450,593			81,825,785
Total Assets	$		1,016,828,044	$	1,010,832,532

CAPITALIZATION AND LIABILITIES:
Common stock, $1 par value, 25,604,000 and 24,975,604 shares issued and outstanding, respectively	$		25,604,000	$	24,975,604
Capital in excess of par value	319,308,693			306,727,950
Retained earnings	35,329,151			39,848,572
Accumulated other comprehensive income (net) (Note 3)	6,327,311			7,272,705
Total common stockholders’ equity	386,569,155			378,824,831
Long-term debt (Note 4)
Note payable to securitization trust	50,000,000			50,000,000
Obligations under capital lease	167,323			297,655
First mortgage bonds and secured debt	140,456,404			150,692,450
Unsecured debt	209,433,981			209,402,515
	400,057,708			410,392,620
Current liabilities:
Accounts payable and accrued liabilities	26,465,452			34,102,261
Commercial paper	—			13,000,000
Customer deposits	5,637,201			5,251,359
Interest accrued	7,395,033			2,836,241
Taxes accrued	8,785,329			1,389,389
Current maturities of long-term debt	10,489,212			429,140
Obligations under capital lease	225,578			205,556
Unrealized loss in fair value of derivatives (Note 3)	388,950			583,140
	59,386,755			57,797,086
Noncurrent liabilities and deferred credits:
Regulatory liabilities (Note 4)	14,805,504			17,600,422
Deferred income taxes	133,116,638			125,065,620
Unamortized investment tax credits	5,154,935			5,581,000
Postretirement benefits other than pensions	7,926,960			8,088,674
Unrealized loss in fair value of derivative contracts (Note 3)	635,100			80,350
Minority interest	1,120,301			1,159,953
Other	8,054,988			6,241,976
	170,814,426			163,817,995
Total Capitalization and Liabilities	$		1,016,828,044	$	1,010,832,532

See accompanying Notes to Financial Statements.

THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED STATEMENT OF CASH FLOWS (UNAUDITED)

	Nine Months Ended September 30,
	2004			2003

Operating activities:
Net income	$	19,890,826		$	24,605,416
Adjustments to reconcile net income to cash flows:
Depreciation and amortization	26,381,028			24,125,184
Pension expense	2,254,161			2,893,813
Deferred income taxes, net	7,672,530			14,087,774
Investment tax credit, net	(426,065		)	(450,014				)
Allowance for equity funds used during construction	(53,985		)	—
Issuance of common stock and stock options for incentive plans	1,705,053			984,473
Unrealized gain/(loss) on derivatives	(98,770		)	207,956
Cash flows impacted by changes in:
Accounts receivable and accrued unbilled revenues	(5,223,429		)	(6,721,232				)
Fuel, materials and supplies	(683,932		)	1,830,108
Prepaid expenses and deferred charges	(604,759		)	(1,998,134				)
Accounts payable and accrued liabilities	(8,762,094		)	(12,181,128				)
Customer deposits, interest and taxes accrued	12,340,573			10,906,013
Other liabilities and other deferred credits	1,586,076			779,611
Accumulated provision – rate refunds	—			(18,718,679				)

Net cash provided by operating activities	$	55,977,213		$			40,351,161

Investing activities:
Capital expenditures – regulated	(27,937,042		)	(52,420,316				)
Capital expenditures and other investments- non-regulated	(2,271,715		)	(3,316,401				)

Net cash used in investing activities	(30,208,757		)	(55,736,717				)

Financing activities:
Payment of interest rate derivative	—			(2,683,000				)
Proceeds from issuance of common stock	11,504,086			4,887,466
Proceeds from issuance of senior notes	—			98,000,000
Long-term debt issuance costs	—			(996,752				)
Redemption of senior notes	—			(100,025,000				)
Premium paid on extinguished debt	—			(9,072,688				)
Discount on issuance of senior notes	—			(568,400				)
Redemption of first mortgage bonds	—			(18,000				)
Net (repayments) proceeds from short-term borrowings	(13,000,000		)	36,459,000
Dividends	(24,410,247		)	(21,816,801				)
Net (repayments) proceeds from non-regulated notes payable	(219,917		)	214,025
Other	(109,989		)	(113,929				)

Net cash provided by (used in) financing activities	(26,236,067		)	4,265,921

Net decrease in cash and cash equivalents	(467,611		)	(11,119,635				)

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

Cash and cash equivalents at end of period	$	12,640,586		$		3,319,592

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, 2003.

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

Note 2 - Recently Issued Accounting Standards

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

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

Our postemployment medical plan provides prescription drug coverage for Medicare-eligible retirees. Our accumulated postretirement benefit obligation (APBO) and net cost recognized for other postemployment benefits (OPEB) now reflect the effects of the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act). The provisions of the Act provide for a federal subsidy, beginning in 2006, of 28% of prescription drug costs between $250 and $5,000 for each Medicare-eligible retiree who does not join Medicare Part D, to companies whose plans provide prescription drug benefits to their retirees that are “actuarially equivalent” to the prescription drug benefits provided under Medicare. Equivalency must be certified annually by the Federal Government. This subsidy has caused a decrease of $4.9 million in the APBO which will be recognized as an actuarial gain and amortized through the FAS 106 post-retirement expense. In accordance with FASB Staff Position No. 106-1, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003”, issued in January 2004, we elected to defer recognition of the effects of the Act until the earlier of the issuance of final accounting guidance or a significant modification of the plan. FASB Staff Position No. 106-2,

“Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003”, was issued May 19, 2004 and calls for the subsidy to be generally accounted for in the first annual or interim period starting after June 15, 2004. As a result, we adopted FASB Staff Position No. 106-2 in the third quarter of 2004 and recorded a $0.48 million credit to our FAS 106 post-retirement expense retroactive to January 1, 2004. This resulted in a reduction to our FAS 106 cost of $0.16 million for each of the first three quarters of 2004.

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

Note 3 - Risk Management and Derivative Financial Instruments

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

As of September 30, 2004, we have recorded the following assets and liabilities representing the fair value of derivative financial instruments held as of that date and subject to the reporting requirements of FAS 133.

Current assets	$	7,097,900
Current liabilities	$	388,950
Noncurrent assets	$	4,192,150
Noncurrent liabilities	$	635,100

A $6,327,311 net of tax, unrealized gain representing the change in 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 $3,878,029 on this unrealized gain is included in deferred taxes. These amounts will be adjusted cumulatively on a monthly basis during the contract periods beginning October 1, 2004 and ending on August 31, 2008. At the end of each settlement period, any gain or loss for that period related to contracts settled will be reclassified to fuel expense.

We record unrealized gains/(losses) on the overhedged portion of our gas hedging activities in “Fuel” under the Operating Revenues Deductions section of our income statements as allowed by FAS 133 since all of our gas hedging activities are related to stabilizing fuel costs as part of our fuel procurement program and are not speculative activities.

The following table sets forth the “mark-to-market” pre-tax gains/(losses) from the overhedged portion of our hedging activities included in “Fuel” (in millions):

	September 30, 2004			September 30, 2003
Quarters ended	$	(0.3	)	$	(0.04	)
Nine months ended	$	(0.4	)	$	1.0
Twelve months ended	$	(0.5	)	$	2.2

The following table sets forth the actual pre-tax gains/(losses) from the qualified portion of our hedging activities for settled contracts included in “Fuel” (in millions):

	September 30, 2004		September 30, 2003
Quarters ended	$	4.0	$	2.5
Nine months ended	$	9.2	$	8.6
Twelve months ended	$	9.9	$	8.6

The table above does not include a $5.1 million realized gain from an interest rate derivative contract in November 2003 or a $2.7 million realized loss from an interest rate derivative contract in June 2003. See Note 4 — Long-Term Debt (below) for information on our hedging of interest rate exposures.

As of November 5, 2004, 61% of our anticipated volume of natural gas usage for the remainder of year 2004 is hedged at an average price of $3.289 per Dekatherm (Dth). In addition, approximately 60% of our anticipated volume of natural gas usage for the year 2005 is hedged at an average price of $4.705 per Dth, approximately 23% of our anticipated volume of natural gas usage for the year 2006 is hedged at an average price of $4.648 per Dth, approximately 26% of our anticipated volume of natural gas usage for the year 2007 is hedged at an average price of $4.526 per Dth, and approximately 14% of our anticipated volume of natural gas usage for the year 2008 is hedged at an average price of $4.569 per Dth.

Note 4 – Long-Term Debt

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

On November 3, 2003, we issued $62.0 million aggregate principal amount of Senior Notes, 6.70% Series due 2033 for net proceeds of approximately $61.0 million. We used the proceeds from this issuance, along with short-term debt, to redeem three separate series of our outstanding first mortgage bonds: (1) all $2.25 million aggregate principal amount of our First Mortgage Bonds, 9¾% Series due 2020 for approximately $2.4 million, including interest; (2) all $13.1 million aggregate principal amount of our First Mortgage Bonds, 7¼% Series due 2028 for approximately $13.7 million, including interest; and (3) all $45.0 million aggregate principal amount of our First Mortgage Bonds, 7% Series due 2023 for approximately $46.8 million, including interest. The $1.7 million aggregate redemption premiums paid in connection with the redemption of these first mortgage bonds, together with $1.1 million of remaining unamortized issuance costs and discounts on the redeemed first mortgage bonds, were recorded as a regulatory asset and are being amortized as interest expense over the life of the 2033 Notes. On May 16, 2003, we entered into an interest rate derivative contract with an outside counterparty to hedge against the risk of a rise in interest rates impacting the 2033 Notes prior to their issuance. Upon issuance of the 2033 Notes, the realized gain of $5.1 million from the derivative contract was recorded as a regulatory liability and is being amortized over the life of the debt to reduce interest expense.

We “marked-to-market” the fair market value of these contracts at the end of each accounting period as specified in FAS 133 and FAS 149 and included them in Other Comprehensive Income until they were reclassified as a regulatory asset upon issuance of the 2013 Notes in June 2003 and a regulatory liability upon issuance of the 2033 Notes in November 2003.

On October 22, 2004, we extended our $100 million unsecured revolving credit facility until May 31, 2006. Borrowings are at the bank’s prime commercial rate or LIBOR plus 100 basis points based on our current credit ratings and the pricing schedule in the line of credit facility. The credit

facility is used for working capital, general corporate purposes and to back-up our use of commercial paper. This facility requires our total indebtedness (which does not include the Trust Preferred Securities or the related note payable to the securitization trust) to be less than 62.5% of our total capitalization at the end of each fiscal quarter and our EBITDA (defined as net income plus interest, taxes, depreciation, amortization and certain other non-cash charges) to be at least two times our interest charges (which includes interest on the note payable to the securitization trust) for the trailing four fiscal quarters at the end of each fiscal quarter. Failure to maintain these ratios 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, 2004. This credit facility is also subject to cross-default if we default on in excess of $5,000,000 in the aggregate of our other indebtedness. There were no borrowings outstanding under this revolver as of September 30, 2004. Our commercial paper borrowings decreased to zero at September 30, 2004 compared to $13 million at December 31, 2003

Note 5 – Commitments, Contingencies and Benefits

Pension and Other Employment and Post -Employment Benefits

Based on the performance of our pension plan assets through January 1, 2003, we were required under the Employee Retirement Income Security Act of 1974 (ERISA) to fund approximately $0.3 million in order to maintain minimum funding levels and contributed this $0.3 million to our pension plan in the first quarter of 2004. We believe we will not be required to fund any additional minimum ERISA amounts for 2004 and 2005.

Our net periodic pension benefit (cost) (related to the application of SFAS 87, “Employers’ Accounting for Pensions”), net of tax, is presented below as a percentage of net income for each of the periods ended September 30, 2004 and 2003:

	% Effect on Net Income
	2004		2003
Three Months Ended	(2.37	)%	(2.95	)%
Nine Months Ended	(5.63	)%	(5.85	)%
Twelve Months Ended	(6.57	)%	(3.59	)%

The above table excludes amounts of our net periodic pension benefit (cost) that are capitalized for labor associated with capital projects, since they do not impact net income.

We expect to make OPEB contributions of $3.0 million in 2004, of which $2.2 million has been made as of September 30, 2004, in addition to our current year expenditures for retiree health care expense of approximately $1.4 million. We adopted FASB Staff Position No. 106-2 regarding the new Medicare Prescription Drug Improvement and Modernization Act of 2003 in the third quarter of 2004. The effect of the adoption is reflected in these numbers and the cost numbers below. See Note 2 for further details.

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

	Pension Benefits						OPEB
	Three months ended September 30,
	2004			2003			2004			2003
Service cost	$	0.6		$	0.6		$	0.6		$	0.3
Interest cost	1.6			1.5			0.6			0.8
Expected return on plan assets	(1.9		)	(1.6		)	(0.4		)	(0.4		)
Amortization of prior service cost	0.2			0.2			(0.2		)	—
Amortization of transition obligation	—			—			0.3			0.3
Amortization of net loss	0.3			0.3			0.2			0.4
Net periodic benefit cost	$	0.8		$	1.0		$	1.1		$	1.4

	Pension Benefits						OPEB
	Nine months ended September 30,
	2004			2003			2004			2003
Service cost	$	2.1		$	1.9		$	1.1		$	0.8
Interest cost	4.6			4.4			2.3			2.6
Expected return on plan assets	(5.6		)	(4.8		)	(1.5		)	(1.2		)
Amortization of prior service cost	0.4			0.4			(0.4		)	—
Amortization of transition obligation	—			—			0.8			0.8
Amortization of net loss	0.7			1.0			1.3			1.2
Net periodic benefit cost	$	2.2		$	2.9		$	3.6		$	4.2

	Pension Benefits						OPEB
	Twelve months ended September 30,
	2004			2003			2004			2003
Service cost	$	2.7		$	2.4		$	1.4		$	1.1
Interest cost	6.1			5.8			3.1			3.3
Expected return on plan assets	(7.2		)	(6.8		)	(1.9		)	(1.5		)
Amortization of prior service cost	0.6			0.6			(0.4		)	—
Amortization of transition obligation	—			(0.1		)	1.1			1.1
Amortization of net (gain) loss	1.0			0.1			1.7			1.4
Net periodic benefit cost	$	3.2		$	2.0		$	5.0		$	5.4

Stock Compensation

We utilize the accounting provisions of FAS 123 “Accounting for Stock-Based Compensation” and recognize compensation expense over the vesting period of stock-based compensation awards based upon the fair-value of the award as of the date of issuance. There were 26,200 stock awards granted in the first quarter of 2004 relating to the performance-based restricted stock award portion of our stock incentive plan. All such grants are made in the first quarter with respect to each plan year.

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

	Options	Weighted Average Exercise Price
Outstanding, beginning of year	118,900	$	19.83
Granted	54,200	$	21.79
Exercised	—	—
Forfeited	—	—
Outstanding as of September 30, 2004	173,100	$	20.45
Exercisable as of September 30, 2004	—	—

In addition, we issued 30,650 shares in the first nine months of 2004 relating to our 401(k) Plan matching contributions.

We recognized $0.2 million and $0.1 million in compensation expense for the three month periods ended September 30, 2004 and 2003, respectively, $0.7 million and $0.2 million in compensation expense for the nine month periods ended September 30, 2004 and 2003, respectively, and $0.8 million and $0.3 million in compensation expense for the twelve months ended September 30, 2004 and 2003, respectively, for the above-noted plans, as well as our employee stock purchase plan.

Note 6 – Regulatory Matters

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

Note 7 – Accounts Receivable - Other

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

	September 30, 2004		December 31, 2003
Accounts receivable for meter loops, meter bases, line extensions, highway projects, etc.	$	1.7	$	1.9
Accounts receivable for insurance reimbursement for Energy Center	2.2		—
Accounts receivable of our non-regulated subsidiary companies	2.7		1.7
Accounts receivable from Westar Generating, Inc. for commonly-owned facility	0.7		0.5
Taxes receivable – overpayment of estimated income taxes	0.6		3.2
Accounts receivable for true-up on maintenance contracts	2.2		1.0
Other	0.3		0.9
Total accounts receivable – other	$	10.4	$	9.2

The $2.2 million accounts receivable for insurance reimbursement for Energy Center relates to $4.1 million of total expenses for repairs to our Unit No. 2 combustion turbine at the Energy Center, less our $1.0 million deductible which was expensed in the first quarter of 2004 and $0.85 million of insurance reimbursement received as of September 30, 2004. We expect the $2.2 million to be reimbursed by our insurer.

The increase to $2.7 million in accounts receivable of our non-regulated subsidiary companies is due mainly to increased trade receivables for Mid-America Precision Products, LLC (MAPP).

The $2.2 million in accounts receivable for true-up on maintenance contracts represents $1.7 million of the balance of gross estimated credits accrued in the last six months of 2003 and the first six months of 2004 and $0.5 million of gross estimated credits accrued during the third quarter of 2004 related to our maintenance contract entered into in July 2001 for the State Line Combined Cycle Unit (SLCC). The measurement periods for these maintenance contracts run from July 1 through June 30 of each year. 40% of these credits belong to Westar Generating, Inc., the owner of 40% of the SLCC, and has been recorded in accounts payable as of September 30, 2004.

Note 8 - Regulated – Other Operating Expense

The following table sets forth the major components comprising “Regulated – other” under “Operating Revenue Deductions” on our consolidated statements of income (in millions) for all periods presented ended September 30:

	Third Quarter 2004		Third Quarter 2003		9 Months Ended 2004		9 Months Ended 2003		12 Months Ended 2004		12 Months Ended 2003
Transmission and distribution expense	$	1.8	$	2.1	$	5.5	$	6.1	$	7.5	$	8.2
Power operation expense (other than fuel)	2.5		2.5		7.5		6.9		9.7		9.3
Customer accounts & assistance expense	1.7		1.7		5.2		4.9		7.0		6.6
Employee pension expense	0.7		0.9		2.1		2.6		2.9		2.4
Employee healthcare plan	1.8		1.7		5.6		5.0		7.4		6.5
General office supplies and expense	1.9		1.6		5.4		4.6		7.1		6.2
Administrative and general expense	2.0		2.0		6.5		6.2		8.4		8.0
Allowance for uncollectible accounts	0.2		0.2		1.2		0.7		1.6		1.0
Miscellaneous expense	—		—		0.1		0.1		0.1		0.1
Total	$	12.6	$	12.7	$	39.1	$	37.1	$	51.7	$	48.3

Note 9 - Non-regulated Businesses

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

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

	For the quarter ended September 30,
	2004						2003
	Non-Regulated			Total Company			Non-Regulated				Total Company
Statement of Income Information
Revenues	$	5,384,396	*	$	96,741,531		$	5,005,329		*	$	101,029,025
Operating income (loss)	$	(285,754	)	$	23,672,747		$	(354,875		)	$	24,155,903
Net income (loss)	$	(372,140	)	$	16,235,098		$		(514,841	)	$	16,297,937
Minority interest	$	(39,328	)	$	(39,328	)	$	(135,266		)	$	(135,266		)
Capital Expenditures
	$	622,201		$	10,328,949		$		1,068,963		$		9,441,672

	As of September 30, 2004							As of December 31, 2003
	Non-Regulated				Total Company			Non-Regulated				Total Company
Balance Sheet Information
Total assets	$	25,734,111			$	1,016,828,044		$	24,439,244			$	1,010,832,532
Minority interest	$		(1,120,301	)	$	(1,120,301	)	$		(1,159,953	)	$		(1,159,953	)

	For the nine-months-ended September 30,
	2004								2003
	Non-Regulated					Total Company			Non-Regulated			Total Company
Statement of Income Information
Revenues	$	16,259,040			*	$	251,275,915		$	15,348,617	*	$	252,537,686
Operating income (loss)	$		(888,294		)	$	42,236,145		$	(973,325	)	$	49,058,379
Net income (loss)	$		(1,142,605		)	$	19,890,826		$	(1,422,049	)	$	24,605,416
Minority interest	$		(106,869		)	$	(106,869	)	$	(441,031	)	$	(441,031		)
Capital Expenditures
	$			2,271,715		$	30,208,757		$	3,316,401		$		55,736,717

	For the twelve-months-ended September 30,
	2004						2003
	Non-Regulated			Total Company			Non-Regulated			Total Company
Statement of Income Information
Revenues	$	22,128,173	*	$	324,243,124		$	20,790,962	*	$	324,415,943
Operating income (loss)	$	(1,019,155	)	$	54,612,285		$	(1,492,569	)	$	60,210,091
Net income (loss)	$	(1,113,216	)	$	24,735,718		$	(2,113,691	)	$	28,252,970
Minority interest	$	(19,471	)	$	(19,471	)	$	(471,785	)	$	(471,785	)
Capital Expenditures
	$	2,862,805		$	40,377,749		$	2,302,169		$	74,529,076

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

FORWARD LOOKING STATEMENTS

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

All such factors are difficult to predict, contain uncertainties that may materially affect actual results, and may be beyond our control. New factors emerge from time to time and it is not possible for management to predict all such factors or to assess the impact of each such factor on us. Any forward-looking statement speaks only as of the date on which such statement is made, and we do not undertake any obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement is made.

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

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

EXECUTIVE SUMMARY

The Empire District Electric Company is an operating public utility engaged in the generation, purchase, transmission, distribution and sale of electricity in parts of Missouri, Kansas, Oklahoma and Arkansas. We also provide water service to three towns in Missouri and have investments in non-regulated businesses including fiber optics, Internet access, utility industry technical training, automated meter reading, close-tolerance custom manufacturing and customer information system software services through our wholly owned subsidiary, EDE Holdings, Inc.

The primary drivers of our electric operating revenues in any period are: (1) weather, (2) rates we can charge our customers, (3) customer growth, (4) the inability to recover increases in fuel costs in rates due to the lack of a fuel adjustment provision in Missouri and (5) general economic conditions. Weather affects the demand for electricity for our regulated business. Very hot summers and very cold winters increase demand, while mild weather reduces demand. Residential and commercial sales are impacted more by weather than industrial sales, which are mostly affected by business needs for electricity and general economic conditions. The utility commissions in the states in which we operate, as well as the FERC, set the rates at which we can charge our customers. In order to offset expenses, we depend on our ability to receive adequate and timely rate relief. We continue to assess the need for rate relief in all of the jurisdictions we serve and file for such relief when necessary. Customer growth (growth in the number of our customers) contributes to the demand for electricity. We expect our annual customer growth to be approximately 1.6% over the next several years.

The primary drivers of our electric operating expenses in any period are: (1) fuel and purchased power expense, (2) maintenance and repairs expense, (3) employee pension and health care costs, (4) taxes and (5) non-cash items such as depreciation and amortization expense. Fuel and purchased power costs are our largest expense items. Several factors affect these costs, including fuel and purchased power prices, plant outages and weather, which drives customer demand. In order to control the price we pay for fuel and purchased power, we have entered into long and short-term agreements to purchase coal and natural gas for our energy supply and currently engage in hedging activities in an effort to minimize our risk from volatile natural gas prices. We enter into contracts with counterparties relating to our future natural gas requirements that lock in prices (with respect to predetermined percentages of our expected future natural gas needs) in an attempt to lessen the volatility in our fuel expense and improve predictability.

The following pre-tax variances and tax-affected per share variances explain the primary factors in the results between periods. During the third quarter of 2004, basic earnings per weighted average share of common stock were $0.64 as compared to $0.71 in the third quarter of 2003 and 2004 diluted earnings per weighted average share were $0.63 as compared to $0.71 in the third quarter of 2003. Our third quarter 2004 results were positively impacted by a $4.2 million pre-tax net decrease in total fuel and purchased power costs, which increased earnings by approximately $0.12 per share, and by continued sales growth (adjusted for normal weather), which increased earnings per share by an estimated $0.08. Unfavorable weather conditions in the third quarter of 2004 decreased earnings per share by an estimated $0.19 and affected off-system wholesale revenues, which resulted in decreased earnings of approximately $0.03 per share. This decrease in off-system wholesale revenues, along with a related decrease in off-system wholesale costs, relates to the decrease in purchased power costs discussed above. The calculation of our earnings per share for the third quarter of 2004 also gives effect to the dilution from the sale of 2.3 million shares of our common

stock in December 2003 and January 2004 of an estimated $0.08 per share. See “- Liquidity and Capital Resources” below.

For the nine months ended September 30, 2004, basic and diluted earnings per weighted average share of common stock were $0.78 as compared to $1.08 for the nine months ended September 30, 2003. Earnings were positively impacted an estimated $0.18 per share from continued sales growth (adjusted for normal weather) and an estimated $0.05 per share due to decreased interest charges on long-term debt. The May 2003 FERC rate increase (average rate increase of 14.00%) and August 2003 Oklahoma rate increase (average rate increase of 10.99%) increased earnings an estimated $0.03 per share. Earnings per share for the nine months ended September 30, 2004, were negatively impacted predominantly by unfavorable weather conditions that decreased earnings per share by an estimated $0.16 per share and an approximate $3.8 million pre-tax decrease in off system wholesale revenues which decreased earnings per share by approximately $0.11. A related decrease in off-system wholesale costs reflects the decrease in purchased power costs due to the non-renewal of short-term contracts for firm energy discussed under “- Operating Revenue Deductions” below. A $1.9 million pre-tax net increase in total fuel and purchased power costs (and the inability to recover most of this increased fuel cost in rates due to the lack of a fuel adjustment provision in Missouri) and increases in depreciation and amortization expense, other taxes and other operating expenses (primarily employee health care costs, stock compensation expense and customer accounts expense) decreased earnings per share by approximately $0.06, $0.05, $0.04 and $0.03, respectively. The calculation of our earnings per share for the nine months ended September 30, 2004 also gives effect to the dilution from the sales of 2.3 million shares of our common stock in December 2003 and January 2004 of an estimated $0.09 per share. See “- Liquidity and Capital Resources” below.

For the twelve months ended September 30, 2004, basic earnings per weighted average share of common stock decreased to $1.00 and diluted earnings per weighted average share were $0.99 as compared to $1.25 for basic and diluted earnings per weighted average share of common stock for the twelve months ended September 30, 2003. Earnings were positively impacted an estimated $0.24 per share from continued sales growth (adjusted for normal weather) and an estimated $0.10 per share from the May 2003 FERC rate increase (average rate increase of 14.00%) and August 2003 Oklahoma rate increase (average rate increase of 10.99%). Also positively impacting earnings an estimated $0.04 per share were decreased interest charges on long-term debt. Earnings per share for the twelve months ended September 30, 2004, were negatively impacted predominantly by unfavorable weather conditions and an approximate $7.0 million pre-tax decrease in off system wholesale revenues which reduced earnings per share by approximately $0.20 each. A related decrease in off-system purchased power costs was approximately $4.6 million and is included in the total purchased power decrease. This reflects the non-renewal of short-term contracts for firm energy discussed under “- Operating Revenue Deductions” below. Also negatively impacting earnings were pre-tax increases of $2.4 million in depreciation and amortization expense and $1.4 million in other taxes, which decreased earnings per share by approximately $0.07 and $0.04, respectively. Increases in pension expense, employee health care expense and stock and compensation expense decreased earnings per share by approximately $0.03 each. Earnings per share for the twelve months ended September 30, 2004, were negatively impacted by a $0.7 million pre-tax increase in total fuel and purchased power costs (and the inability to recover most of this increased fuel cost in rates due to the lack of a fuel adjustment provision in Missouri), which reduced earnings per share by $0.02. A smaller net loss from our non-regulated businesses contributed $0.04 per share to earnings this period versus the same period last year. The calculation of our earnings per share for the twelve months ended September 30, 2004 also gives effect to the dilution from the sales of 2.3 million

shares of our common stock in December 2003 and January 2004 of an estimated $0.10 per share. See “- Liquidity and Capital Resources” below.

On April 30, 2004, we filed a request with the Missouri Public Service Commission (MPSC) for an annual increase in base rates for our Missouri electric customers in the amount of $38,282,294, or 14.82%, and a proposed interim energy charge (IEC) similar to the one approved in our 2001 case. On May 20, 2004, we filed a request with the MPSC to implement the proposed IEC no later than June 15, 2004. However, the MPSC denied this request on August 12, 2004. The IEC issue remains a part of the general rate case still before the MPSC.

On July 14, 2004, we filed a request with the Arkansas Public Service Commission for an annual increase in base rates for our Arkansas electric customers in the amount of $1,428,225, or 22.1%. See “-Results of Operations - Rate Matters” below.

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, 2004, compared to the same periods ended September 30, 2003.

Electric Operating Revenues and Kilowatt-Hour Sales

Of our total electric operating revenues during the third quarter of 2004 approximately 40.4% were from residential customers, 32.5% from commercial customers, 17.5% from industrial customers, 4.2% from wholesale on-system customers, 1.4% from wholesale off-system transactions and 4.0% from miscellaneous sources, primarily transmission services. The percentage changes from the prior year periods in kilowatt-hour (“Kwh”) sales and operating revenues by major customer class were as follows:

	On-System kWh Sales (in millions)
	Third Quarter 2004	Third Quarter 2003	%* Change		9 MOE Sept 30, 2004	9 MOE Sept 30, 2003	%* Change		12 MOE Sept 30, 2004	12 MOE Sept 30, 2003	%* Change
Residential	450.7	507.5	(11.2	)%	1,303.6	1,341.4	(2.8	)%	1,690.5	1,734.9	(2.6	)%
Commercial	394.0	394.1	0.0		1,068.6	1,049.4	1.8		1,406.0	1,377.8	2.1
Industrial	292.7	284.6	2.8		820.8	786.3	4.4		1,093.2	1,044.6	4.7
Wholesale	83.8	87.8	(4.6	)	231.7	238.3	(2.7	)	302.0	313.0	(3.5	)
Other***	27.7	28.0	(0.8	)	80.8	78.4	3.0		106.3	103.9	2.3
Total On-System	1,248.9	1,302.0	(4.1	)	3,505.5	3,493.8	0.3		4,598.0	4,574.2	0.5

	On-System Operating Revenues ($ in millions)
	Third Quarter 2004		Third Quarter 2003		%* Change		9 MOE Sept 30, 2004		9 MOE Sept 30, 2003		%* Change		12 MOE Sept 30, 2004		12 MOE** Sept 30, 2003		%* Change
Residential	$	36.9	$	40.8	(9.7	)%	$	96.2	$	98.1	(1.9	)%	$	123.4	$	124.3	(0.7	)%
Commercial	29.6		29.4		0.6		71.2		70.0		1.7		91.8		88.6		3.6
Industrial	15.9		15.5		2.5		40.1		38.6		3.7		52.1		49.7		4.9
Wholesale	3.9		3.8		2.4		10.5		9.6		9.4		13.3		12.2		9.2
Other***	2.2		2.2		0.5		5.8		5.6		3.4		7.5		7.2		3.9
Total On-System	$	88.5	$	91.7	(3.6	)	$	223.8	$	221.9	0.9		$	288.1	$	282.0	2.2

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

**Revenues exclude amounts collected under the Interim Energy Charge during 2002 which were 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 decreased 4.1% during the third quarter of 2004 as compared to the third quarter of 2003 while associated revenues decreased approximately $3.3 million, or 3.6%, primarily due to cooler temperatures during July and August of 2004 as compared to the same months in 2003. Total cooling degree days (the number of degrees that the average temperature for that period was above 65° F) for the third quarter of 2004 were 20.5% less than the same period last year and 16.2% less than the 20-year average. The Oklahoma rate increase discussed below and continued sales growth (adjusted for normal weather) contributed an estimated $0.1 million and $2.8 million, respectively, to revenues during the third quarter of 2004 with weather having a negative effect of an estimated $6.5 million. Our customer growth was 1.6% in 2003, 1.8 % during the third quarter of 2004 and 1.7% during the first nine months of 2004. We expect our annual customer growth to approximate 1.6% over the next several years.

Residential kWh sales and revenues decreased during the third quarter of 2004 due mainly to the cooler temperatures discussed above while commercial kWh sales were virtually the same as last year’s third quarter sales. Residential and commercial revenues were positively impacted by continued sales growth and slightly by the August 2003 Oklahoma rate increase.

Industrial kWh sales and revenues, which are not particularly weather sensitive, increased during the third quarter of 2004 due mainly to a continuing increase in sales to our oil pipeline pumping customers.

On-system wholesale kWh sales decreased during the third quarter of 2004 reflecting the weather conditions discussed above. Revenues associated with these FERC-regulated sales increased as a result of the fuel adjustment clause applicable to such sales. This clause permits the distribution of changes in fuel and purchased power costs to customers.

For the nine months ended September 30, 2004, kWh sales to our on-system customers increased approximately 0.3% while the associated revenues increased approximately $1.9 million, or 0.9%. Rate increases contributed an estimated $1.2 million to revenues with sales growth (adjusted for normal weather) contributing an estimated $6.4 million and weather having a negative effect of an estimated $5.7 million. Residential kWh sales and associated revenues decreased during the nine months ended September 30, 2004 due mainly to the third quarter cooler temperatures

discussed above as well as mild temperatures in the first quarter of 2004. Commercial kWh sales and associated revenues increased, mainly due to continued sales growth and the August 2003 Oklahoma rate increase. Industrial kWh sales and revenues increased for the nine month period reflecting the addition of two new oil pipeline pumping stations on our system that became fully operational in June 2003. On-system wholesale kWh sales decreased reflecting the weather conditions discussed above as well as 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 and revenues, but less than one-half percent of our total on-system sales and revenues in 2002, are now included in our off-system revenues. 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.

For the twelve months ended September 30, 2004, kWh sales to our on-system customers increased approximately 0.5% while the associated revenues increased approximately $6.1 million, or 2.2%, as compared to the same period ended September 30, 2003. Rate increases contributed an estimated $3.4 million to revenues with sales growth (adjusted for normal weather) contributing an estimated $8.4 million and weather having a negative effect estimated at $7.0 million. Residential kWh sales and associated revenues decreased during the twelve months ended September 30, 2004 due mainly to the weather conditions discussed above. Commercial kWh sales and associated revenues increased, mainly due to continued sales growth and the August 2003 Oklahoma rate increase. Industrial sales and revenues increased during the twelve-month period reflecting the addition of the two new oil pipeline pumping stations on our system that became fully operational in June 2003. On-system wholesale kWh sales decreased during the twelve-month period reflecting the weather conditions discussed above and the change in customer status in June 2003 of the on-system wholesale customer/aggregator which elected to go off-system and purchase power from us at market-based rates. 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.

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
FERC -Electric	March 17, 2003	1,672,000		14.00	%	May 1, 2003
Oklahoma -Electric	March 4, 2003	766,500		10.99	%	August 1, 2003

The 2001 Missouri order approved an annual Interim Energy Charge, or IEC, of approximately $19.6 million effective October 1, 2001 and expiring two years later which was collected subject to refund (with interest). The 2002 Missouri electric order called for us to refund all funds collected under the IEC, with interest, by March 15, 2003. The refunds were made in the first

quarter of 2003 and did not have a material impact on our earnings in any of the years from 2001 through 2003.

On April 30, 2004, we filed a request with the Missouri Public Service Commission (MPSC) for an annual increase in base rates for our Missouri electric customers in the amount of $38,282,294, or 14.82%. As part of the filing, we asked the Commission to consider, in addition to a traditional ratemaking approach, two options that would allow us to recover our actual fuel and purchased power expenses: an IEC, subject to refund, similar to the one approved in our 2001 case, or a fuel adjustment clause, that would reflect actual fuel prices. We also asked for a return on equity (ROE) of 11.65% and an annual increase in Missouri depreciation expense of approximately $10 million. Any new rates approved as a result of this request are not expected to be effective until late in the first quarter of 2005.

On May 20, 2004, we filed a request with the MPSC to implement the proposed IEC no later than June 15, 2004. However, the MPSC denied this request on August 12, 2004. The IEC issue remains a part of the general rate case still before the MPSC.

On September 20, 2004, the Staff of the MPSC filed direct testimony in response to our initial April 2004 filing. The MPSC Staff recommended an IEC be adopted for a period of 24 months, due to the extreme volatility currently exhibited by natural gas prices, an ROE range of 8.29% to 9.29% with 8.79% as the mid-point and a reduction in the current ordered annual depreciation accrual of an additional $1.8 million, based on June 30, 2004 plant in service balances. We currently employ depreciation rates ordered in the 2000 Missouri rate case. A hearing on the general rate case is scheduled to begin on December 6, 2004. We are unable to predict the outcome or quantify the potential impact on our future financial position at this time.

On July 14, 2004, we filed a request with the Arkansas Public Service Commission for an annual increase in base rates for our Arkansas electric customers in the amount of $1,428,225, or 22.1%. Any new rates approved as a result of this request are not expected to be effective until the second quarter of 2005.

We will continue to assess the need for rate relief in all of the jurisdictions we serve and file for such relief when necessary.

Off-System 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 for the applicable periods ended September 30,:

	2004						2003
	Third Quarter		Nine Months Ended		Twelve Months Ended		Third Quarter		Nine Months Ended		Twelve Months Ended
(in millions)
Revenues	$	2.1	$	9.1	$	11.2	$	3.5	$	13.1	$	18.6
Expenses	1.2		5.2		6.6		2.2		8.4		11.6
Net Revenue*	$	1.0	$	3.8	$	4.6	$	1.3	$	4.7	$	7.1

*Differences could occur due to rounding.

The decrease in revenues less expenses for both the nine months ended and twelve months ended periods in 2004 as compared to the prior year periods resulted primarily from the non-renewal of short-term contracts for firm energy that ran from January 2002 through June 2003. We sold this energy in the wholesale market when it was not required to meet our own customers’ needs during that period. These expenses are included in our discussions of purchased power costs below.

In December 1999, the FERC issued Order No. 2000 which encourages the development of regional transmission organizations (RTOs). RTOs are designed to independently control the wholesale transmission services of the utilities in their regions thereby facilitating open and more competitive bulk power markets. The Southwest Power Pool (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 and on February 10, 2004, the FERC approved the SPP RTO with conditions. Upon completion of the conditions, the SPP would gain status and FERC acceptance as an RTO. On October 4, 2004, the FERC granted RTO status to the SPP and ordered the SPP to resolve rate “pancaking” (accumulation of multiple access charges) concerns and assure the independence of its proposed market monitor as conditions of the decision. FERC also ordered SPP to finalize a joint operating agreement with MISO.

On October 27, 2003 we filed a notice of intent with the SPP for the right to withdraw from the SPP effective October 31, 2004 because of 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 requires approval from the FERC. We retained the option, however, to rescind such notice on or before October 31, 2004 and remain a member of the SPP, which we did on October 25, 2004. At the same time, we filed a new notice of intent with the SPP for the right to withdraw from the SPP effective October 31, 2005. We will be seeking authorization from Missouri, Kansas and Arkansas to participate in and transfer functional control of our transmission facilities to the SPP RTO should we decide to remain a member. We are unable to quantify the potential impact of membership in the RTO on our future financial position, results of operation or cash flows at this time, but will continue to evaluate the situation and make a decision whether or not to continue membership with the SPP.

Operating Revenue Deductions

During the third quarter of 2004, total operating expenses decreased approximately $3.8 million (5.0%) compared with the same period last year. Fuel costs decreased approximately $2.9 million (14.0%) while purchased power costs decreased $1.3 million (10.1%) during the third quarter of 2004. The decrease in fuel and purchased power costs was primarily due to decreased demand in the third quarter of 2004 as compared to the same period in 2003 primarily due to cooler temperatures during July and August of 2004 and to $1 million recorded as fuel expense in the third quarter of 2003 for a payment made in the fourth quarter of 2003 pursuant to a settlement with Enron of a fuel contract dispute. The positive effect of our gas hedging program also reduced fuel cost by $1.1 million compared to the same period last year. We expect fuel costs to increase in 2005 due to changes in delivered prices resulting from the expiration of our long-term coal and freight contracts. We currently have a long-term contract, expiring in December 2004, with a subsidiary of Peabody Holding Company, Inc. for the supply of low sulfur Western coal (Powder River Basin) at the Asbury and Riverton Plants. We also currently have a contract with Union Pacific Railroad Company and The Kansas City Southern Railway Company which provides for transportation of the Powder River Basin coal which will expire in June 2005. We have accepted binding proposals and are negotiating contractual terms and conditions to finalize both a new coal contract and a new transportation contract. The delivered price of coal under the new contracts is expected to be higher

than the current price during the first and second quarters of 2005, but we expect the delivered price increase to be substantially mitigated beginning in the third quarter of 2005.

Regulated - other operating expenses decreased $0.1 million (0.6%) during the period primarily due to a $0.3 million decrease in transmission expense and a $0.2 million decrease in employee pension expense partially offset by a $0.1 million increase in employee health care expense and an approximate $0.2 million increase in stock compensation costs. Non-regulated operating expense for all periods presented is discussed below under “- Non-regulated Items.”

Maintenance and repairs expense was virtually the same for the third quarter of 2004 as for the same period in 2003. A $0.5 million increase in distribution maintenance was offset by a $0.3 million decrease in maintenance costs at our power plants and a $0.2 million decrease in transmission maintenance costs. Depreciation and amortization expense increased approximately $0.4 million (5.8%) during the quarter due to increased plant in service. The provision for income taxes decreased $0.5 million (5.3%) during the third quarter of 2004 due to a decrease in taxable income. Other taxes increased approximately $0.3 million (5.7%) during the third quarter of 2004 due mainly to increased property taxes reflecting our additions to plant in service.

During the nine months ended September 30, 2004, total operating expenses increased approximately $5.6 million (2.7%) compared with the same period last year. Fuel costs increased approximately $10.3 million (24.5%) but were partially offset by an $8.5 million (18.1%) decrease in purchased power costs during the period. The increase in fuel costs was primarily due to increased generation by both our coal fired and gas fired units during the first nine months of 2004 (an estimated $5.4 million), lower volumes of hedged natural gas in 2004 as compared to 2003 with higher prices for the unhedged portion of the natural gas that we burned in our gas-fired units and a smaller net gain from our natural gas derivative contracts (which reduces fuel expense) in the first nine months of 2004 ($8.8 million) as compared to the first nine months of 2003 ($9.6 million). Also contributing to the decrease in fuel expense for the first nine months of 2004 was the $1 million recorded as fuel expense in the third quarter of 2003 pursuant to the settlement with Enron of a fuel contract dispute. The decrease in purchased power costs primarily reflected a shift from serving our energy needs with purchased power to generating our own power reflecting that it was more economical to run our own generating units during the nine months ended September 30, 2004 than to purchase power. The 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 costs during the nine months ended September 30, 2004 as compared to the same period last year was $1.9 million (2.1%).

Regulated - other operating expenses for the first nine months of 2004 increased approximately $1.9 million (5.2%) primarily due to a $0.6 million increase in employee health care costs, an approximate $0.6 million increase in stock compensation costs and a $0.9 million increase to customer accounts expense, of which $0.4 million was a first quarter 2004 addition to bad debt expense. These increases were partially offset by $0.6 million decrease in transmission expense and a $0.6 million decrease in employee pension expense.

Maintenance and repairs expense increased $1.2 million (7.9%) for the nine months ended September 30, 2004 compared to the same period in 2003 primarily due to the $1.0 million insurance deductible recorded to expense in the first quarter of 2004 related to the maintenance on the Energy Center’s Unit No. 2 which experienced a rotating blade failure on January 7, 2004 (which caused damage throughout the machine) and to the second and third quarter maintenance costs related to repairs at the Energy Center not subject to insurance recovery. Also contributing to this increase was a $0.6 million increase in distribution maintenance and a $0.9 million increase in maintenance costs for the SLCC as compared to the prior year due mainly to a $1.8 million true-up credit (our share of the credit as 60% owners of the SLCC) received from Siemens Westinghouse in June 2003 related to

our maintenance contract for the period July 2002 through June 2003 for the SLCC. These increases were partially offset by a $1.4 million decrease in maintenance costs for our coal-fired units during the first nine months of 2004 as compared to the prior year, reflecting the maintenance outages during the second quarter of 2003 when the Iatan Plant underwent a planned boiler outage, the Riverton Plant’s Unit No. 7 had a 12-day scheduled spring maintenance outage and Unit No. 8 had an extended maintenance outage that ran from February 14, 2003 until May 14, 2003.

Depreciation and amortization expense increased approximately $1.6 million (7.7%) during the nine-month period due to increased plant in service. Total provisions for income taxes decreased $3.2 million (23.5%) due to decreased taxable income. Other taxes increased $1.5 million (12.1%) during the nine months ended September 30, 2004 due mainly to increased property taxes reflecting our additions to plant in service and increased city taxes in the first quarter of 2004 as compared to the first quarter of 2003 when we had a decrease in city taxes resulting from the refund of the IEC in the first quarter of 2003.

During the twelve months ended September 30, 2004, total operating expenses increased approximately $5.4 million (2.1%) compared with the same period in 2003. Total fuel costs increased approximately $13.6 million (27.7%) but were partially offset by a decrease in total purchased power costs of approximately $12.9 million (20.0%) during the twelve-month period. The increase in fuel costs was due to increased generation by both our coal-fired and gas-fired units (an estimated $6.1 million), reflecting the non-renewal of short-term contracts for firm energy that ran from January 2002 through June 2003, as well as lower volumes of hedged natural gas in 2004 as compared to 2003 with higher prices for the unhedged portion of the natural gas that we burned in our gas-fired units. Also contributing to the increase in fuel costs was a smaller net gain from our natural gas derivative contracts (which reduces fuel expense) during the twelve months ended September 30, 2004 ($9.4 million) as compared to the prior year period ($10.8 million). The decrease in purchased power costs primarily reflected a shift from serving our energy needs with purchased power to generating our own power, reflecting that it was more economical to run our own generating units during the twelve months ended September 30, 2004 than to purchase power. This decrease in purchased power costs also reflects the non-renewal of the short-term contracts for firm energy discussed above. The net increase in fuel and purchased power costs during the twelve months ended September 30, 2004 as compared to the same period last year was $0.7 million (0.6%).

Regulated – other operating expenses increased approximately $3.4 million (7.1%) during the twelve months ended September 30, 2004, compared to the same period last year due primarily to increases in employee pension expense of approximately $0.9 million (due in part to increased amortization of prior year asset losses as required by the provisions of FAS 87), employee health care expense of approximately $0.9 million, stock compensation expense of approximately $0.6 million and a $1.0 million increase to customer accounts expense of which $0.6 million consisted of additions to bad debt expense in the fourth quarter of 2003 ($0.2 million) and the first quarter of 2004 ($0.4 million). These increases were partially offset by a $0.7 million decrease in transmission expense.

Maintenance and repairs expense increased approximately $0.4 million (2.0%) during the twelve months ended September 30, 2004 compared to the prior period, due to a $1.2 million increase in maintenance costs at the Energy Center primarily related to the Unit No. 2 repairs and related insurance deductible and a $0.7 million increase in distribution maintenance costs. These increases were partially offset by a $1.4 million decrease in maintenance costs for our coal-fired units reflecting the 2003 second quarter maintenance outages discussed above. Depreciation and amortization expense increased approximately $2.4 million (8.7%) for the twelve month period due to increased plant in service. Total provision for income taxes decreased $2.7 million (17.9%) due to decreased taxable income during the current period. Other taxes increased approximately $1.4

million (8.4%) due mainly to increased property taxes reflecting our additions to plant in service and increased city taxes in the first quarter of 2004 as compared to the first quarter of 2003 when we had a decrease in city taxes resulting from the refund of the IEC in the first quarter of 2003.

Non-regulated Items

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

During the third quarter of 2004, total non-regulated operating revenue increased approximately $0.4 million (8.5%) while total non-regulated operating expense increased approximately $0.2 million (4.2%) as compared to the third quarter of 2003. Our non-regulated businesses generated a $0.4 million net loss in the third quarter of 2004 as compared to a $0.5 million net loss in the third quarter of 2003.

For the nine-months ended September 30, 2004, total non-regulated operating revenue increased approximately $0.9 million (6.1%) while total non-regulated operating expense increased approximately $0.6 million (4.1%) as compared to the same period in 2003. Our non-regulated businesses generated a $1.1 million net loss for the nine months ended September 30, 2004 as compared to a $1.4 million net loss during the same period in 2003.

For the twelve-months ended September 30, 2004, total non-regulated operating revenue increased approximately $1.2 million (6.0%) while total non-regulated operating expense decreased approximately $0.2 million (0.8%) compared with the same period in 2003. The increase in revenues was mainly due to the activities of Conversant, Inc., a software company which began business in early 2002. Conversant markets Customer Watch, an Internet-based customer information system software, and began contributing license revenues in the fourth quarter of 2003.

Our non-regulated businesses generated a $1.1 million net loss for the twelve-months ended September 30, 2004 as compared to a $2.1 million net loss for the same period in 2003. This smaller net loss contributed $0.04 per share to earnings this period versus the same period last year.

Nonoperating Items

Total allowance for funds used during construction (AFUDC) was virtually the same during the third quarter of 2004 as compared to the same period in 2003. AFUDC decreased $0.2 million for the first nine months of 2004 as compared to the first nine months of 2003 and $0.4 million during the twelve months ended September 30, 2004 as compared to the prior year due to lower levels of construction for those periods ended September 30, 2004.

Total interest charges on long-term debt decreased $0.1 million (1.4%) during the third quarter of 2004 compared to the same period last year and $1.3 million (6.8%) for the nine months ended September 30, 2004 as compared to the same period in 2003 primarily reflecting the refinancing we accomplished in 2003 by calling higher interest debt issues and replacing them with debt issues at lower interest rates. Total interest charges on long-term debt decreased $1.0 million (4.1%) for the twelve months ended September 30, 2004 as compared to the same period in 2003 primarily reflecting the refinancings discussed above offset by interest on additional long-term debt as a result of our repaying short-term debt in December 2002 with the issuance of $50 million of our unsecured 7.05% Senior Notes which mature on December 15, 2022. See “ - Liquidity and Capital Resources” for further information. Commercial paper interest decreased $0.2 million during the third quarter of 2004, $0.4 million for the nine months ended and $0.5 million for the twelve months ended September 30, 2004 as compared to the same periods in 2003, reflecting decreased usage of short-term debt.

Other Comprehensive Income

The change in the fair value of the effective portion of our open gas contracts and our interest rate derivative contracts and the gains and losses on contracts settled during the periods being reported, including the tax effect of these items, are reflected in our Consolidated Statement of Comprehensive Income as the net change in unrealized gain or loss. This net change is recorded as accumulated other comprehensive income in the capitalization section of our balance sheet and does not affect net income or earnings per share. All of these contracts have been designated as cash flow hedges. The unrealized gains and losses accumulated in comprehensive income are reclassified to fuel, or interest expense, in the periods in which they are actually realized or no longer qualify for hedge accounting.

The following table sets forth the net-of-tax increase/(decrease) in Other Comprehensive Income (in millions):

	September 30, 2004			September 30, 2003
Quarters ended	$	0.1		$	(2.7	)
Nine months ended	$	(0.9	)	$	1.0
Twelve months ended	$	(1.3	)	$	3.2

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

LIQUIDITY AND CAPITAL RESOURCES

Cash Provided by Operating Activities

Our net cash flows provided by operating activities increased $15.6 million during the first nine months of 2004 as compared to the first nine months of 2003, despite a $4.7 million decrease in net income. This was primarily due to the refunding of $18.7 million to our Missouri electric customers in the first quarter of 2003 (the amount of the IEC, with interest, collected between October 2001 and December 2002). Other major factors positively impacting cash flows provided by operating activities during the first nine months of 2004 compared to the same period in 2003 were a $2.3 million increase due to changes in depreciation and amortization due to increased plant in service in April 2003 and a $3.4 million increase due to changes in accounts payable and accrued liabilities. Negatively impacting cash provided by operating activities were a decrease in deferred income taxes of $6.4 million and a $2.5 million increase in cash used for fuel, materials and supplies.

Given recent market returns, we could face a position at December 31, 2004 where our accumulated pension benefit obligation exceeds the fair value of our plan assets. If this situation exists, we would be required to recognize an additional minimum pension liability, as prescribed by SFAS No. 87, or we may elect to make an additional cash contribution to our pension plan. If the additional liability is recognized, it would reduce our prepaid pension asset and reduce Other Comprehensive Income. The amount of the liability, or cash contribution, if any, will depend upon asset returns experienced in the remainder of 2004. There would be no effect to net income if this liability is recognized or if a cash contribution is made.

Capital Requirements and Investing Activities

Our net cash flows used in investing activities decreased $25.5 million during the first nine months of 2004 as compared to the first nine months of 2003, primarily reflecting the completion of the two FT8 peaking units at the Empire Energy Center in April 2003.

Our capital expenditures totaled $10.3 million during the third quarter of 2004 compared to $9.2 million for the same period in 2003. For the nine months ended September 30, 2004, capital expenditures totaled $30.2 million compared to $55.7 million for the same period in 2003 reflecting the completion of the FT8 peaking units in April 2003. These capital expenditures include AFUDC, capital expenditures to retire assets and benefits from salvage.

A breakdown of these capital expenditures for the quarter and nine months ended September 30, 2004 is as follows:

	Quarter Ended September 30, 2004		Nine Months Ended September 30, 2004
Distribution and transmission system additions	$	6.4	$	19.3
Additions and replacements – Asbury	0.2		1.3
Additions and replacements – Riverton, Iatan, Ozark Beach, Energy Center, State Line Combined Cycle	0.7		2.1
New generation	0.4		0.3
System mapping project	0.7		1.5
Fiber optics (non-regulated)	0.4		1.1
Transportation	0.0		1.0
Other non-regulated capital expenditures	0.2		1.1
Storms	0.6		1.3
Other	0.4		1.0
Retirements and salvage (net)	0.3		0.2
Total	$	10.3	$	30.2

For the first nine months of 2004, approximately 100% of our capital expenditures were paid with internally generated funds (net cash provided by operating activities less dividends paid). We estimate our capital expenditures to be approximately $56.5 million for 2005 and $84.4 million for 2006. As in the past, we intend to utilize short-term debt or the proceeds of sales of long-term debt or common stock (including common stock sold under our Employee Stock Purchase Plan, our Dividend Reinvestment and Stock Purchase Plan, and our 401(k) Plan and ESOP) to finance any additional amounts needed beyond those provided by operating activities for such capital expenditures. We will continue to utilize short-term debt as needed to support normal operations or other temporary requirements.

Financing Activities

Our net cash flows provided by financing activities decreased $30.5 million during the first nine months of 2004 as compared to the first nine months of 2003 resulting in a $26.2 million use of cash in the current year. Our net cash flows provided by financing activities were primarily affected by borrowing and repayment of short-term debt (commercial paper).

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

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

On December 17, 2003, we sold to the public in an underwritten offering, 2,000,000 newly issued shares of our common stock for $42.3 million. The net proceeds of approximately $40.3 million were used to repay short-term debt and for other general corporate purposes. On January 8, 2004, the underwriters purchased an additional 300,000 shares for approximately $6.1 million to cover over-allotments. The proceeds were added to our general funds. Through 2004 and 2003 we issued $5.4 million and $4.9 million, respectively in common stock, primarily through our employee stock purchase and dividend reinvestment plans.

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

On October 22, 2004, we extended our $100 million unsecured revolving credit facility until May 31, 2006. See Note 4 –Long-Term Debt under Notes to Consolidated Financial Statements (Unaudited) for information on our revolving credit facility.

Restrictions in our mortgage bond indenture could affect our liquidity. The Mortgage contains a requirement that for new first mortgage bonds to be issued, our net earnings (as defined in the Mortgage) for any twelve consecutive months within the fifteen months preceding issuance must be two times the annual interest requirements (as defined in the Mortgage) on all first mortgage bonds then outstanding and on the prospective issue of new first mortgage bonds. Our earnings for the twelve months ended September 30, 2004 would permit us to issue approximately $203.0 million of new first mortgage bonds based on this test with an assumed interest rate of 7.0%.

As of September 30, 2004, the ratings for our securities were as follows:

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

On July 22, 2004, Standard & Poor’s notified us that they had upgraded their rating on our first mortgage bonds from BBB to A- and on September 28, 2004 notified us that they had placed that rating on credit watch with negative implications reflecting, “prospects for erosion of Empire’s pressured financial condition if recent testimony by the MPSC staff in Empire’s pending general rate case is ultimately endorsed by the MPSC.” Moody’s currently has a negative outlook on Empire. These ratings indicate the agencies’ assessment of our ability to pay interest, distributions, dividends and principal on these securities. The lower the rating the higher the cost of the securities when they are sold. Ratings below investment grade (Baa3 or above for Moody’s and BBB- or above for Standard & Poor’s) may also impair our ability to issue short-term debt as described above, commercial paper or other securities or make the marketing of such securities more difficult.

CONTRACTUAL OBLIGATIONS

Set forth below is information summarizing our contractual obligations as of September 30, 2004:

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

Long-Term Debt (w/o discount)	$	358.1	$	10.0	$	—	$	—	$	348.1
Note Payable to Securitization Trust	50.0		—		—		—		50.0
Capital Lease Obligations	0.4		0.2		0.2		—		—
Operating Lease Obligations	0.4		0.4		—		—		—
Purchase Obligations*	210.6		40.1		62.9		47.7		59.9
Open Purchase Orders	12.7		10.1		1.2		1.2		0.2
Other Long-Term Liabilities**	3.2		0.5		2.5		0.2		—

Total Contractual Obligations	$	635.4	$	61.3	$	66.8	$	49.1	$	458.2

*includes fuel and purchased power contracts.

**Other Long-term Liabilities primarily represents 100% of the long-term debt issued by Mid-America Precision Products, LLC. EDE Holdings, Inc. is the 25% guarantor of a $2.4 million note included in this total amount.

OFF-BALANCE SHEET ARRANGEMENTS

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

CRITICAL ACCOUNTING POLICIES

See “Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report Form 10-K for the year ended December 31, 2003 for a discussion of our critical accounting policies. There were no changes in these policies in the nine months ended September 30, 2004.

RECENTLY ISSUED ACCOUNTING STANDARDS

See Note 2 of “Notes to Consolidated Financial Statements (Unaudited)”.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

Market risk is the exposure to a change in the value of a physical asset or financial instrument, derivative or non-derivative, caused by fluctuations in market variables such as interest rates or commodity prices. We handle our commodity market risk in accordance with our established Energy Risk Management Policy, which may include entering into various derivative transactions. We utilize derivatives to manage our gas commodity market risk and to help manage our exposure resulting from purchasing most of our natural gas on the volatile spot market for the generation of power for our native-load customers. See Note 3 of “Notes to Consolidated Financial Statements (Unaudited)” for further information.

Interest Rate Risk. We are exposed to changes in interest rates as a result of significant financing through our issuance of commercial paper. We manage our interest rate exposure by limiting our variable-rate exposure to a certain percentage of total capitalization, as set by policy, and by monitoring the effects of market changes in interest rates.

If market interest rates average 1% more in 2004 than in 2003, our interest expense would increase, and income before taxes would decrease by less than $150,000. This amount has been determined by considering the impact of the hypothetical interest rates on our commercial paper balances as of December 31, 2003. These analyses do not consider the effects of the reduced level of overall economic activity that could exist in such an environment. In the event of a significant change in interest rates, management would likely take actions to further mitigate its exposure to the change. However, due to the uncertainty of the specific actions that would be taken and their possible effects, the sensitivity analysis assumes no changes in our financial structure.

Commodity Price Risk. We are exposed to the impact of market fluctuations in the price and transportation costs of coal, natural gas, and electricity and employ established policies and procedures to manage the risks associated with these market fluctuations, including utilizing derivatives.

We have entered into long-term contracts for the purchase of coal in order to manage our exposure to fuel prices. We satisfied 72.6% of our 2003 fuel supply need through coal. The majority of our anticipated 2004 supply of coal has been acquired at fixed prices (including standard adjustments). Future coal supplies will be acquired using a combination of short-term and long-term contracts, some of which are being negotiated. We are exposed to changes in market prices for natural gas we must purchase to run our combustion turbine generators. Our natural gas procurement program is designed to minimize our risk from volatile natural gas prices. We enter into physical forward and financial derivative contracts with counterparties relating to our future natural gas requirements that lock in prices (with respect to predetermined percentages of our expected future natural gas needs) in an attempt to lessen the volatility in our fuel expense and improve predictability. As of November 5, 2004, 61% of our anticipated volume of natural gas usage for the remainder of year 2004 is hedged. See Note 3 of “Notes to Consolidated Financial Statements (Unaudited)” for further information.

Item 4. Controls and Procedures.

As of the end of the period covered by this report, an evaluation was carried out, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15 of the Securities Exchange Act of 1934. Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure

controls and procedures were effective, in all material respects, with respect to the recording, processing, summarizing and reporting, within the time periods specified in the SEC’s rules and forms, of information to be required to be disclosed by us in reports that we file or submit under the Exchange Act.

There have been no changes in our internal control over financial reporting identified in connection with the evaluation described above that occurred during the third quarter of 2004 that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.

PART II. OTHER INFORMATION

Item 5. Other Information.

At September 30, 2004, our ratio of earnings to fixed charges was 2.26x. See Exhibit (12) hereto.

On July 22, 2004, Mr. Bill D. Helton of Amarillo, Texas was appointed as a Class III Director of Empire effective August 1, 2004 and will stand for election at our Annual Meeting of Stockholders in April 2005.

On September 10, 2004, Mr. Robert L. Lamb announced his retirement from Empire’s Board of Directors at the end of January 2005.

Item 6. Exhibits.

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

(31)(a) Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

(31)(b) Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

(32)(a) Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.*

(32)(b) Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.*

* This certification accompanies this Report pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and shall not be deemed filed by the Company for purposes of Section 18 or any other provision of the Securities Exchange Act of 1934, as amended.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	THE EMPIRE DISTRICT ELECTRIC COMPANY
	Registrant


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


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

November 9, 2004