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 June 30, 2005 or

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

		For the transition period from to .

Commission file number: 1-3368

THE EMPIRE DISTRICT ELECTRIC COMPANY

(Exact name of registrant as specified in its charter)

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

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

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

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

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

As of August 1, 2005, 25,951,932 shares of common stock were outstanding.

PART I. FINANCIAL INFORMATION

Item 1. Consolidated Financial Statements

EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)

	Three Months Ended June 30,
	2005			2004
Operating revenues:
Electric	$	81,987,854		$	71,410,564
Water	363,441			337,528
Non-regulated (Note 9)	5,540,252			5,554,469
	87,891,547			77,302,561
Operating revenue deductions:
Fuel	25,086,740			17,824,919
Purchased power	11,711,664			12,423,307
Regulated – other (Note 8)	13,776,022			12,747,749
Non-regulated (Note 9)	5,724,970			5,692,004
Maintenance and repairs	5,696,487			6,061,135
Depreciation and amortization	9,120,396			7,621,586
Provision for income taxes	1,607,335			1,092,151
Other taxes	4,637,659			4,281,284
	77,361,273			67,744,135

Operating income	10,530,274			9,558,426
Other income and deductions:
Allowance for equity funds used during construction	28,137			27,732
Interest income	34,949			10,468
Provision for other income taxes	20,995			64,206
Minority interest	(22,689		)	(109,761		)
Other - non-operating income	—			67,016
Other - non-operating expense	(206,042		)	(230,453		)
	(144,650		)	(170,792		)
Interest charges:
Long-term debt – other	5,967,784			6,159,686
Note payable to securitization trust	1,062,500			1,062,500
Commercial paper	109,463			3,623
Allowance for borrowed funds used during construction	(53,073		)	(24,089		)
Other	140,864			107,775
	7,227,538			7,309,495
Net income	$	3,158,086		$	2,078,139

Weighted average number of common shares outstanding - basic	25,845,970			25,408,592

Weighted average number of common shares outstanding - diluted	25,894,742			25,455,030

Earnings per weighted average share of common stock - basic	$	0.12		$	0.08

Earnings per weighted average share of common stock - diluted	$	0.12		$	0.08

Dividends per share of common stock	$	0.32		$	0.32

See accompanying Notes to Consolidated Financial Statements.

	Six Months Ended June 30,
	2005			2004
Operating revenues:
Electric	$	155,223,272		$	143,147,927
Water	684,473			673,607
Non-regulated (Note 9)	11,518,729			10,712,850
	167,426,474			154,534,384
Operating revenue deductions:
Fuel	47,837,942			34,920,611
Purchased power	23,826,954			26,489,880
Regulated – other (Note 8)	27,910,849			26,411,956
Non-regulated (Note 9)	11,859,615			10,993,801
Maintenance and repairs	10,496,549			11,244,020
Depreciation and amortization	17,073,392			15,193,553
Provision for income taxes	1,511,907			1,949,593
Other taxes	9,212,801			8,767,572
	149,730,009			135,970,986

Operating income	17,696,465			18,563,398
Other income and deductions:
Allowance for equity funds used during construction	48,525			27,732
Interest income	103,444			29,202
Provision for other income taxes	56,561			109,392
Minority interest	(49,658		)	(67,541		)
Other - non-operating income	—			67,016
Other - non-operating expense	(419,718		)	(464,537		)
	(260,846		)	(298,736		)
Interest charges:
Long-term debt – other	12,119,387			12,319,741
Note payable to securitization trust	2,125,000			2,125,000
Commercial paper	109,463			11,799
Allowance for borrowed funds used during construction	(86,841		)	(36,208		)
Other	260,185			188,602
	14,527,194			14,608,934
Net income	$	2,908,425		$	3,655,728

Weighted average number of common shares outstanding - basic	25,794,216			25,346,003

Weighted average number of common shares outstanding - diluted	25,841,391			25,396,857

Earnings per weighted average share of common stock - basic	$	0.11		$	0.14

Earnings per weighted average share of common stock - diluted	$	0.11		$	0.14

Dividends per share of common stock	$	0.64		$	0.64

See accompanying Notes to Consolidated Financial Statements.

	Twelve Months Ended June 30,
	2005			2004
Operating revenues:
Electric	$	314,665,689		$	305,794,285
Water	1,380,181			1,381,245
Non-regulated (Note 9)	22,385,856			21,355,088
	338,431,726			328,530,618
Operating revenue deductions:
Fuel	77,357,874			65,546,304
Purchased power	50,182,692			53,065,722
Regulated – other (Note 8)	54,461,255			51,766,895
Non-regulated (Note 9)	23,838,396			21,585,645
Maintenance and repairs	20,046,159			21,047,277
Depreciation and amortization	32,677,693			29,899,778
Provision for income taxes	10,616,349			13,064,929
Other taxes	18,578,366			17,458,626
	287,758,784			273,435,176

Operating income	50,672,942			55,095,442
Other income and deductions:
Allowance for equity funds used during construction	142,465			27,732
Interest income	279,421			53,719
Provision for other income taxes	(298,796		)	304,863
Minority interest	325,990			(115,410		)
Other - non-operating income	—			120,178
Other - non-operating expense	(924,279		)	(948,969		)
	(475,199		)	(557,887		)
Interest charges:
Long-term debt – other	24,440,458			24,792,371
Note payable to securitization trust	4,250,000			2,125,000
Trust preferred distributions by subsidiary holding solely parent debentures	—			2,125,000
Commercial paper	438,224			370,040
Allowance for borrowed funds used during construction	(148,687		)	(24,963		)
Other	117,518			351,550
	29,097,513			29,738,998
Net income	$	21,100,230		$	24,798,557

Weighted average number of common shares outstanding - basic	25,690,338			24,177,053

Weighted average number of common shares outstanding - diluted	25,732,489			24,228,183

Earnings per weighted average share of common stock - basic	$	0.82		$	1.03

Earnings per weighted average share of common stock - diluted	$	0.82		$	1.02

Dividends per share of common stock	$	1.28		$	1.28

See accompanying Notes to Consolidated Financial Statements.

THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	Three Months Ended June 30,
	2005			2004

Net income	$	3,158,086		$	2,078,139
Reclassification adjustments for losses/(gains) included in net income or reclassified to regulatory asset or liability	1,146,885			(2,280,500		)
Change in fair market value of open derivative contracts for period	4,339,915			1,136,380
Income taxes	(2,084,984		)	434,765
Net change in unrealized derivative contracts	3,401,816			(709,355		)

Comprehensive income	$	6,559,902		$	1,368,784

	Six Months Ended June 30,
	2005			2004

Net income	$	2,908,425		$	3,655,728
Reclassification adjustments for losses/(gains) included in net income or reclassified to regulatory asset or liability	1,133,685			(5,218,130		)
Change in fair market value of open derivative contracts for period	16,180,035			3,585,230
Income taxes	(6,579,214		)	620,502
Net change in unrealized derivative contracts	10,734,506			(1,012,398		)

Comprehensive income	$	13,642,931		$	2,643,330

	Twelve Months Ended June 30,
	2005			2004

Net income	$	21,100,230		$	24,798,557
Reclassification adjustments for losses/(gains) included in net income or reclassified to regulatory asset or liability	(5,119,205		)	(13,561,761		)
Change in fair market value of open derivative contracts for period	16,810,205			7,103,192
Income taxes	(4,442,580		)	2,454,256
Net change in unrealized derivative contracts	7,248,420			(4,004,313		)

Comprehensive income	$	28,348,650		$	20,794,244

See accompanying Notes to Consolidated Financial Statements

THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEET (UNAUDITED)

	June 30, 2005		December 31, 2004
Assets
Plant and property, at original cost:
Electric	$	1,240,970,462	$	1,221,384,998
Water	9,549,516		9,201,314
Non-regulated	25,108,243		23,668,864
Construction work in progress	27,543,536		8,653,720
	1,303,171,757		1,262,908,896
Accumulated depreciation and amortization	421,228,975		405,873,917
	881,942,782		857,034,979

Current assets:
Cash and cash equivalents	3,793,319		12,593,369
Accounts receivable - trade, net	26,786,635		20,052,892
Accrued unbilled revenues	9,977,236		7,599,964
Accounts receivable – other (Note 7)	8,906,229		12,874,123
Fuel, materials and supplies	33,292,536		32,044,113
Unrealized gain in fair value of derivative contracts (Note 3)	4,862,370		2,867,550
Prepaid expenses	2,167,997		1,952,236
	89,786,322		89,984,247

Noncurrent assets and deferred charges:
Regulatory assets (Note 6)	54,747,784		52,127,262
Unamortized debt issuance costs	5,831,227		5,881,384
Unrealized gain in fair value of derivative contracts (Note 3)	18,535,250		4,142,900
Prepaid pension asset	10,523,827		13,973,827
Other	4,253,814		4,393,939
	93,891,902		80,519,312
Total Assets	$	1,065,621,006	$	1,027,538,538

(Continued)

See accompanying Notes to Consolidated Financial Statements.

THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEET (UNAUDITED)

	June 30, 2005		December 31, 2004
Capitalization and Liabilities
Common stock, $1 par value, 25,939,498 and 25,695,972 shares issued and outstanding, respectively	$	25,939,498	$	25,695,972
Capital in excess of par value	325,911,946		321,632,092
Retained earnings	15,470,102		29,078,105
Accumulated other comprehensive income, net of income tax (Note 3)	13,508,727		2,774,221

Total common stockholders’ equity	380,830,273		379,180,390

Long-term debt:
Note payable to securitization trust	50,000,000		50,000,000
Obligations under capital lease	31,079		122,570
First mortgage bonds and secured debt	110,158,094		140,363,500
Unsecured debt	249,215,182		209,430,556
Total long-term debt	409,404,355		399,916,626

Total long-term debt and common stockholders’ equity	790,234,628		779,097,016

Current liabilities:
Accounts payable and accrued liabilities	41,817,945		36,926,520
Current maturities of long-term debt	492,884		10,462,211
Obligations under capital lease	235,864		239,684
Commercial paper	18,040,000		—
Customer deposits	6,049,163		5,724,211
Interest accrued	2,488,666		2,700,402
Unrealized loss in fair value of derivative contracts (Note 3)	1,012,500		1,030,100
Taxes accrued	6,128,337		1,411,355
Other current liabilities	2,173,285		708,643
	78,438,644		59,203,126

Commitments, contingencies and benefits (Note 5)
Noncurrent liabilities and deferred credits:
Regulatory liabilities (Note 6)	30,218,998		30,225,020
Deferred income taxes	138,973,211		132,694,686
Unamortized investment tax credits	4,991,771		5,041,000
Postretirement benefits other than pensions	7,778,762		8,248,004
Unrealized loss in fair value of derivative contracts (Note 3)	1,135,050		1,505,800
Minority interest	754,984		705,326
Other	13,094,958		10,818,560
	196,947,734		189,238,396

Total Capitalization and Liabilities	$	1,065,621,006	$	1,027,538,538

See accompanying Notes to Consolidated Financial Statements.

EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED STATEMENT OF CASH FLOWS (UNAUDITED)

	Six Months Ended June 30,
	2005			2004
Operating activities:
Net income	$	2,908,425		$	3,655,728
Adjustments to reconcile net income to cash flows from operating activities:
Depreciation and amortization	19,327,859			17,477,824
Pension expense	3,502,447			1,479,447
Deferred income taxes, net	258,616			1,227,602
Investment tax credit, net	(49,229		)	(68,170		)
Allowance for equity funds used during construction	(48,525		)	(27,732		)
Issuance of common stock and stock options for incentive plans	972,944			1,277,650
Unrealized (gain)/loss on derivatives	(179,250		)	(114,650		)
Cash flows impacted by changes in:
Accounts receivable and accrued unbilled revenues	(4,425,671		)	(5,166,683		)
Fuel, materials and supplies	(1,248,423		)	(97,816		)
Prepaid expenses and deferred charges	(680,613		)	(387,605		)
Accounts payable and accrued liabilities	7,925,964			5,108,462
Customer deposits, interest and taxes accrued	4,830,198			4,760,658
Other liabilities and other deferred credits	1,900,416			219,665

Net cash provided by operating activities	34,995,158			29,344,380

Investing activities:
Capital expenditures – regulated	(40,822,374		)	(18,151,468		)
Capital expenditures and other investments – non-regulated	(1,478,671		)	(1,647,904		)

Net cash (used) in investing activities	(42,301,045		)	(19,799,372		)

Financing activities:
Proceeds from issuance of common stock	3,550,436			9,475,268
Net short-term borrowings (repayments)	15,005,461			(13,124,119		)
Proceeds from issuance of senior notes	40,000,000			—
Redemption of first mortgage bonds	(40,000,000		)	—
Dividends	(16,516,428		)	(16,237,896		)
Premium paid on extinguished debt	(1,162,500		)	—
Long-term debt issuance costs	(448,896		)	—
Payment of interest rate derivative	(1,385,935		)	—
Discount on issuance of senior notes	(220,000		)	—
Redemption of senior notes	(5,000		)	—
Repayments from non-regulated notes payable	(215,991		)	(194,085		)
Other	(100,310		)	(70,861		)

Net cash used in financing activities	(1,494,163		)	(20,151,693		)

Net decrease in cash and cash equivalents	(8,800,050		)	(10,606,685		)

Cash and cash equivalents at beginning of period	12,593,369			13,108,197

Cash and cash equivalents at end of period	$	3,793,319		$	2,501,512

See accompanying Notes to Consolidated Financial Statements.

Note 3 – Risk Management and Derivative Financial Instruments

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

We have recorded the following assets and liabilities (in thousands) representing the fair value of qualifying derivative financial instruments held as of June 30, 2005 and December 31, 2004 and subject to the reporting requirements of FAS 133:

	June 30, 2005		December 31, 2004
Current assets	$	4,862	$	2,868
Noncurrent assets	18,535		4,143

Current liabilities	1,013		1,030
Noncurrent liabilities	1,135		1,506

A $13.5 million, net of tax, net unrealized gain representing the fair market value of the effective position of these contracts is recognized as Accumulated Other Comprehensive Income in the capitalization section of the balance sheet. The total tax effect of $8.3 million on this gain is recorded in deferred taxes. These amounts will be adjusted cumulatively on a monthly basis during the determination periods beginning July 1, 2005 and ending on September 30, 2011. At the end of each determination period, any previously unrealized gain or loss for that period related to the instrument will be reclassified to fuel expense.

We record unrealized gains/(losses) on the overhedged portion of our gas hedging activities, if any, in “Fuel” under the Operating Revenue Deductions section of our income statements 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 “mark-to-market” pre-tax gains/(losses) from our hedging activities included in “Fuel” (in thousands) for each of the periods ended June 30:

	Three Months Ended					Six Months Ended					Twelve Months Ended
	2005		2004			2005		2004			2005		2004
Overhedged Portion	$	311	$	(150	)	$	504	$	(32	)	$	1,242	$	(145	)
Qualified Portion	$	239	$	2,281		$	252	$	5,218		$	6,505	$	8,462

As of July 29, 2005, 69.7% of our anticipated volume of natural gas usage for the remainder of year 2005 is hedged at an average price of $4.68 per Dekatherm (Dth). In addition, the following percentages of our anticipated volume of natural gas usage for the next six years are hedged at the following average prices per Dth:

Year	% Hedged		Average Price
2006	53	%	$	5.212
2007	43	%	$	4.766
2008	21	%	$	4.569
2009-2011	40	%	$	4.522

See Note 4 – Long-Term Debt and Short-Term Borrowings (below) for information on our hedging of interest rates.

Note 4 – Long-Term Debt and Short-Term Borrowings

On April 1, 2005, we redeemed our $10 million First Mortgage Bonds, 7.60% Series due April 1, 2005, using short-term debt. On June 27, 2005, we issued $40 million aggregate principal amount of our Senior Notes, 5.8% Series due 2035 (2035 Notes), for net proceeds of approximately $39.4 million less $0.1 million of legal fees. We used the net proceeds from this issuance to redeem all $30 million aggregate principal amount of our First Mortgage Bonds, 7.75% Series due 2025 for approximately $31.3 million, including interest and a redemption premium, and to repay short-term debt. The $1.2 million redemption premium paid in connection with the redemption of these first mortgage bonds, together with $2.4 million of remaining unamortized loss on reacquired debt and $0.3 million of unamortized debt expense, were recorded as a regulatory asset and are being amortized as interest expense over the life of the 2035 Notes. We had entered into an interest rate derivative contract in May 2005 to hedge against the risk of a rise in interest rates impacting the 2035 Notes prior to their issuance. Costs associated with the interest rate derivative (primarily due to interest rate fluctuations) amounted to approximately $1.4 million and were recorded as a regulatory asset and are being amortized over the life of the 2035 Notes.

On July 15, 2005, we entered into a $150 million five year unsecured credit agreement with UMB Bank, N.A., as administrative agent, Bank of America, N.A., as syndication agent, and the other lenders party thereto. This agreement replaces our pre-existing $100 million unsecured credit agreement, which was terminated upon entering into the new agreement. The credit agreement provides for $150 million of revolving loans to be available for working capital, general corporate purposes and to back-up our use of commercial paper. Interest on borrowings under the credit agreement accrues at a rate equal to, at our option, (i) the bank’s prime commercial rate plus a margin or (ii) LIBOR plus a margin, in each case based on our then current credit ratings. This agreement requires our total indebtedness (which does not include our 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 will result in an event of default under the credit facility and will prohibit us from borrowing funds thereunder. We are in compliance with these ratios as of June 30, 2005. This credit agreement is also subject to cross-default if we default on in excess of $10 million in the aggregate on our other indebtedness. There were no outstanding borrowings under this agreement at July 15, 2005.

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, 2004 and January 1, 2005, we were not required under the Employee Retirement Income Security Act of 1974 (ERISA) to fund any additional minimum ERISA amounts with respect to 2004 or 2005.

We expect to make Other Post-Employment Benefits (OPEB) contributions of $6.5 million in 2005, of which $3.3 million has been made as of June 30, 2005.

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

	Pension Benefits						OPEB
	Three months ended June 30
	2005			2004			2005			2004
Service cost	$	875		$	742		$	550		$	249
Interest cost	1,725			1,536			975			834
Expected return on plan assets	(1,925		)	(1,866		)	(600		)	(517		)
Amortization of prior service cost	125			139			(150		)	(152		)
Amortization of transition obligation	—			—			275			271
Amortization of net loss	925			189			575			531
Net periodic benefit cost	$	1,725		$	740		$	1,625		$	1,216

	Pension Benefits						OPEB
	Six months ended June 30
	2005			2004			2005			2004
Service cost	$	1,750		$	1,484		$	1,100		$	498
Interest cost	3,450			3,072			1,950			1,668
Expected return on plan assets	(3,850		)	(3,732		)	(1,200		)	(1,034		)
Amortization of prior service cost	250			278			(300		)	(305		)
Amortization of transition obligation	—			—			550			542
Amortization of net loss	1,850			377			1,150			1,063
Net periodic benefit cost	$	3,450		$	1,479		$	3,250		$	2,432

	Pension Benefits						OPEB
	Twelve months ended June 30
	2005			2004			2005			2004
Service cost	$	3,025		$	2,756		$	2,120		$	1,040
Interest cost	6,524			6,016			3,273			3,371
Expected return on plan assets	(7,573		)	(6,943		)	(2,125		)	(1,840		)
Amortization of prior service cost	527			559			(605		)	(305		)
Amortization of transition obligation	—			—			1,092			1,084
Amortization of net loss	2,368			1,021			1,829			1,855
Net periodic benefit cost	$	4,871		$	3,409		$	5,584		$	5,205

We began recording a regulatory asset for deferred pension costs during the second quarter of 2005 per our March 10, 2005 Missouri rate case order. As of June 30, 2005, the deferral is approximately $600,000 which we expect to collect in rates in future periods.

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 24,200 stock awards granted in the first half of 2005, all of which were granted in the first quarter, relating to the performance-based restricted stock award portion of our stock incentive plan. The fair value of these awards is equal to the market price of Empire common stock on the date of grant, which will be recorded as expense over the vesting period.

We also utilize stock options as part of our employee compensation plan. The following table summarizes the activity of the stock option portion of our stock incentive plan for the first half of 2005.

	Options	Weighted Average Exercise Price
Outstanding, January 1, 2005	173,100	$	20.45
Granted	39,100	$	22.77
Exercised	69,700	$	20.95
Forfeited	—	—
Outstanding, June 30, 2005	142,500	$	20.84
Exercisable, June 30, 2005	—	—

In addition, we issued 8,988 common shares in the second quarter of 2005 relating to our 401(k) Plan matching contributions.

We recognized the following amounts (in thousands) in compensation expense for all of our stock-based compensation plans, as well as our employee stock purchase plan, for the periods listed.

	June 30, 2005		June 30, 2004
Second Quarter	$	393	$	585
Six Months Ended	862		1,242
Twelve Months Ended	1,847		1,782

Note 6 – Regulatory Matters

All of our regulatory assets as of June 30, 2005, have been allowed recovery in the state of Missouri as a result of the March 10, 2005 rate case order, except for $2.1 million, including a realized loss associated with an interest rate derivative of $1.4 million, which were incurred subsequent to this rate order (see “Note 4 – Long-Term Debt and Short-Term Borrowings” for additional information). We expect our regulatory assets 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 cases in the other jurisdictions to also be allowed recovery since these items have historically been allowed in our rate cases. In addition, losses and gains on our interest rate derivatives were included in our recently approved Missouri rate case. Since these items increase and reduce, respectively, our effective interest cost, we believe it is probable they will also be allowed in our other jurisdictions, as well. At June 30, 2005, our regulatory assets totaled $54.7 million.

We are currently collecting an Interim Energy Charge (IEC) of 0.2131 cents per kilowatt hour of customer usage authorized by the Missouri Public Service Commission (MPSC). This IEC is designed to recover variable fuel and purchased power costs we incur subject to a ceiling (and floor) on the amount recoverable (including realized gains or losses associated with our natural gas hedging program discussed in Note 3) which are higher than such costs included in the base rates allowed in the most recent Missouri rate case. This revenue is recorded when service is provided to the customer and subject to refund to the extent collected amounts exceed variable fuel and purchased power costs. At each balance sheet date, we evaluate the probability that we would be required to refund either a portion or all of the amounts collected under the IEC to ratepayers. At June 30, 2005, no provision for refund has been recorded.

Note 7 – Accounts Receivable - Other

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

	June 30, 2005		December 31, 2004
Accounts receivable for meter loops, meter bases, line extensions, highway projects, etc.	$	1,053	$	1,890
Accounts receivable for insurance reimbursement for Energy Center (1)	—		1,941
Accounts receivable for non-regulated subsidiary companies	2,459		3,062
Accounts receivable from Westar Generating, Inc. for commonly-owned facility	1,059		544
Taxes receivable – overpayment of estimated income taxes	1,743		4,151
Accounts receivable for true-up on maintenance contracts (2)	2,454		1,199
Other	138		87
Total accounts receivable – other	$	8,906	$	12,874

(1) The decrease of $1.9 million accounts receivable for insurance reimbursement for Energy Center at June 30, 2005 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 $3.1 million of insurance reimbursement received as of June 30, 2005 (of which $1.1 million had been received as of December 31, 2004).

(2) The $2.4 million in accounts receivable for true-up on maintenance contracts represents the quarterly estimated credit from Siemens Westinghouse related to our maintenance contract entered into in July 2001 for the State Line Combined Cycle Unit (SLCC) accrued in the last six months of 2004 and the first six months of 2005. The measurement period for this maintenance contract runs from June 1, 2004 through May 31, 2005. 40% of this credit belongs to Westar Generating, Inc., the owner of 40% of the SLCC, and has been recorded in accounts payable as of June 30, 2005.

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 operations (in thousands) for all periods presented ended June 30:

	3 Months Ended 2005		3 Months Ended 2004		6 Months Ended 2005		6 Months Ended 2004		12 Months Ended 2005		12 Months Ended 2004
Transmission and distribution expense	$	2,070	$	1,734	$	3,823	$	3,747	$	7,517	$	7,787
Power operation expense (other than fuel)	2,241		2,331		4,422		4,978		9,427		9,763
Customer accounts & assistance expense	1,752		1,720		3,437		3,465		7,072		6,933
Employee pension expense	995		662		2,467		1,365		4,120		3,102
Employee healthcare plan	2,562		2,003		5,090		3,770		9,320		7,250
General office supplies and expense	1,620		1,817		3,204		3,558		7,337		6,819
Administrative and general expense	2,136		2,112		4,460		4,449		8,163		8,455
Allowance for uncollectible accounts	356		332		927		1,003		1,380		1,556
Miscellaneous expense	44		37		81		77		125		102
Total	$	13,776	$	12,748	$	27,911	$	26,412	$	54,461	$	51,767

Note 9 - Non-regulated Businesses

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

	For the quarter ended June 30,
	2005						2004
	Non-Regulated			Total Company			Non-Regulated			Total Company

Statement of Operations Information
Revenues	$	5,619	*	$	87,892		$	5,635	*	$	77,303
Operating income (loss)	(365		)	10,530			(301		)	9,558
Net income (loss)	(453		)	3,158			(435		)	2,078
Minority interest	(23		)	(23		)	(110		)	(110		)

Capital Expenditures
	$	806		$	26,618		$	1,045		$	10,854

	As of June 30, 2005						As of December 31, 2004
	Non-Regulated			Total Company			Non-Regulated			Total Company
Balance Sheet Information
Total assets	$	25,702		$	1,065,621		$	25,296		$	1,027,539
Minority interest	$	(755	)	$	(755	)	$	(705	)	$	(705	)

	For the six-months-ended June 30,
	2005						2004
	Non-Regulated			Total Company			Non-Regulated			Total Company
Statement of Income Information
Revenues	$	11,676	*	$	167,426		$	10,875	*	$	154,534
Operating income (loss)	(706		)	17,696			(603		)	18,563
Net income (loss)	(883		)	2,908			(770		)	3,656
Minority interest	(50		)	(50		)	(68		)	(68		)
Capital Expenditures
	$	1,479		$	42,301		$	1,648		$	19,799

	For the twelve-months-ended June 30,
	2005					2004
	Non-Regulated			Total Company		Non-Regulated			Total Company
Statement of Operations Information
Revenues	$	22,736	*	$	338,432	$	21,749	*	$	328,531
Operating income (loss)	(1,863		)	50,673		(1,037		)	55,095
Net income (loss)	(1,946		)	21,100		(1,256		)	24,799
Minority interest	326			326		(115		)	(115		)
Capital Expenditures
	$	2,531		$	64,313	$	3,326		$	39,490

*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 generation plans, 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 periodic revision of our construction and capital expenditure plans and cost estimates;

• the performance and liquidity needs 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 certain non-regulated businesses including fiber optics, Internet access, close-tolerance custom manufacturing and customer information system software services through our wholly owned subsidiary, EDE Holdings, Inc. In 2004, 93.0% of our gross operating revenues were provided from the sale of electricity, 0.4% from the sale of water and 6.6% from our non-regulated businesses. There were no significant changes in these percentages for the second quarter of 2005. In April 2005, we were granted a franchise for the water service we provide in Aurora, Missouri.

The primary drivers of our electric operating revenues in any period are: (1) weather, (2) rates we can charge our customers, (3) customer growth and (4) general economic conditions. Weather affects the demand for electricity for our regulated business. Very hot summers and very cold winters increase demand, while mild weather reduces demand. Residential and commercial sales are impacted more by weather than industrial sales, which are mostly affected by business needs for electricity and general economic conditions. The utility commissions in the states in which we operate, as well as the FERC, set the rates at which we can charge our customers. In order to offset expenses, we depend on our ability to receive adequate and timely rate relief. We continue to assess the need for rate relief in all of the jurisdictions we serve and file for such relief when necessary. Customer growth, which is the growth in the number of customers, contributes to the demand for electricity. We expect our annual customer growth to range from approximately 1.6% to 1.8% over the next several years, although our customer growth for the twelve months ended June 30, 2005 was 1.9%.

We define sales growth to be growth in kWh sales excluding the impact of weather. The primary drivers of sales growth are customer growth and general economic conditions.

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, have entered into a 20-year contract with PPM Energy to purchase approximately 550,000 megawatt-hours of energy, or 10% of our annual needs, from the Elk River Windfarm project beginning in December 2005, 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. Our recent Missouri rate case order also contained factors to help mitigate the above costs, including an Interim Energy Charge (IEC), designed to recover variable fuel and purchased power costs we incur which are higher than such costs included in the base rates allowed in our rate case and a change in the recognition of pension costs allowing us to defer the Missouri portion of any costs above the amount included in our rate case as a regulatory asset.

During the second quarter of 2005, basic and diluted earnings per weighted average share of common stock increased to $0.12 as compared to $0.08 in the second quarter of 2004. For the six

months ended June 30, 2005, basic and diluted earnings per weighted average share of common stock were $0.11 as compared to $0.14 for the six months ended June 30, 2004. For the twelve months ended June 30, 2005, basic earnings per weighted average share of common stock were $0.82 as compared to $1.03 for the twelve months ended June 30, 2004 while diluted earnings per weighted average share of common stock were $0.82 as compared to $1.02 for the twelve months ended June 30, 2004. As reflected in the table below, the primary driver for the decline in basic earnings per share for both the six month and twelve month periods ended June 30, 2005 was greater fuel costs, while the primary positive driver for all periods ended June 30, 2005 was increased revenues.

The following reconciliation of basic earnings per share between the three months, six months and twelve months ended June 30, 2004 versus June 30, 2005 is a non-GAAP presentation. We believe this information is useful in understanding the fluctuation in earnings per share between the prior and current year periods. The reconciliation presents the after tax impact of significant items and components of the statement of operations on a per share basis before the impact of additional stock issuances which is presented separately. Earnings per share for the three months, six months and twelve months ended June 30, 2005 and 2004 shown in the reconciliation are presented on a GAAP basis and are the same as the amounts included in the statements of operations. This reconciliation may not be comparable to other companies or more useful than the GAAP presentation included in the statements of operations.

	Three Months Ended			Six Months Ended			Twelve Months Ended
Earnings Per Share – 2004	$	0.08		$	0.14		$	1.03

Revenues
Electric	$	0.28		$	0.32		$	0.24
Non – Regulated	0.00			0.02			0.03
Expenses
Fuel	(0.19		)	(0.34		)	(0.32		)
Purchased power	0.02			0.07			0.08
Regulated – other (employee health care and pension expense)	(0.02		)	(0.06		)	(0.08		)
Regulated – other (all other)	(0.01		)	0.02			0.01
Non – Regulated expenses	0.00			(0.02		)	(0.06		)
Maintenance and repairs	0.01			0.02			0.03
Depreciation and amortization	(0.04		)	(0.05		)	(0.08		)
Other taxes	(0.01		)	(0.01		)	(0.03		)
Interest charges	0.00			0.00			0.02
Other income and deductions	0.00			0.00			0.00
Dilutive effect of additional shares	0.00			0.00			(0.05		)
Earnings Per Share – 2005	$	0.12		$	0.11		$	0.82

Second Quarter Activities

The Missouri Public Service Commission (MPSC) final order issued on March 10, 2005 approved an annual increase in base rates for our Missouri electric customers of approximately $25.7 million, or 9.96%, and also approved an annual IEC of approximately $8.2 million effective March 27, 2005 and expiring three years later. From inception of the IEC through June 30, 2005, we incurred $2.6 million of fuel and purchased power costs in excess of the total cost set in our base rates and the IEC recorded during this period. For additional information regarding the IEC, see “-Results of Operations – Electric Operating Revenues and Kilowatt-Hour Sales - Rate Matters” below.

The Arkansas Public Service Commission (APSC) issued a final order on May 13, 2005, approving an annual increase in base rates for our Arkansas electric customers of approximately $0.6 million, or 7.66%, effective May 14, 2005. On April 29, 2005, we filed a request with the Kansas Corporation Commission for an increase in base rates for our Kansas electric customers in the amount of $4,181,078, or 24.64%. On June 24, 2005, we filed a request with the MPSC for an annual increase in base rates for our Missouri water customers of approximately $523,000, or 38%. For additional information, see “-Results of Operations – Electric Operating Revenues and Kilowatt-Hour Sales - Rate Matters” below.

On February 4, 2005, we filed an application with the MPSC seeking approval of an Experimental Regulatory Plan concerning our possible participation in a new 800-850 MW coal-fired unit (Iatan 2) to be operated by Kansas City Power & Light Company (KCP&L) and located at the site of the existing Iatan Generating Station (Iatan 1) near Weston, Missouri, or other baseload generation options. Our application also sought a certificate of convenience and necessity to participate in Iatan 2, if necessary, and in connection therewith, obtain approval that is intended to provide adequate assurance to potential investors to make financial options available to us concerning this.

On June 10, 2005, we entered into a letter of intent with KCP&L with respect to our potential purchase of an undivided ownership interest in Iatan 2. The estimated construction budget for Iatan 2 is approximately $1.26 billion. The letter of intent relates to an allocation of at least 100 MW of generation capacity (and a proportionate share of the construction, operation and maintenance costs) to us. The letter of intent, insofar as it relates to Iatan 2, is not binding on the parties. The letter of intent also contains a clarification as to our obligations with respect to environmental upgrades at Iatan 1 and an agreement to reallocate certain interests in common facilities at Iatan 1 to the owners of Iatan 2. Empire currently owns a 12% interest in Iatan 1.

On July 18, 2005, we filed a Stipulation and Agreement regarding our Experimental Regulatory Plan with the MPSC for its consideration and approval conditioned upon our participation in Iatan 2. Other parties to the Stipulation and Agreement include the Missouri Department of Natural Resources, the MPSC Staff, two of our industrial customers and the Office of the Public Counsel. The MPSC issued an order on August 2, 2005 approving the Stipulation and Agreement with an effective date of August 12, 2005.

On April 27, 2005, the Missouri House passed Bill SB 179 which authorizes the MPSC to grant fuel adjustment clauses for utilities in the state of Missouri. The bill had previously passed the Missouri Senate. The bill was signed by Governor Blunt on July 14, 2005 and will go into effect January 1, 2006. Prior to that time, rulemaking on how the law will be implemented will need to be completed.

At June 30, 2005, the construction at our Riverton plant was still on schedule for the installation of our new Siemens V84.3A2 combustion turbine, with a summer rated capacity of 155 megawatts, scheduled to be operational in 2007. On December 10, 2004, we entered into a 20-year contract with PPM Energy, to purchase the energy generated at the proposed Elk River Windfarm to be located in Butler County, Kansas. Construction of the windfarm began in May 2005 and is on schedule. We expect that the amount and percentage of electricity we generate by natural gas will decrease in 2006 and in the immediate future thereafter due to this contract. We anticipate purchasing approximately 550,000 megawatt-hours of energy, or 10% of our annual needs, from the project beginning in December 2005. We anticipate the cost of this contract to also be offset by purchasing less higher-priced power from other suppliers or by displacing on-system generation.

Although several of the nation’s utilities are running short of coal due to railroad transportation problems delivering Wyoming coal, we are not currently experiencing a low inventory situation. As of June 30, 2005, we had over 70 days of inventory at our Riverton plant and approximately 75 days of inventory at our Asbury plant. However, given the length of our recent

train cycle times and the railroads’ reluctance to add additional lease train sets, we will be in a declining inventory situation until a change in circumstances occurs, which could have an adverse effect on our fuel and purchased power costs in future periods. Such change in circumstances could be the addition of a lease train set or improved cycle times. Without conservation efforts or a change in circumstances, we expect we will exhaust our inventory at Asbury by the end of 2005. Similarly, slow train cycle times have affected Iatan. We have begun conservation measures at Iatan which we believe to be immaterial to our operations.

RESULTS OF OPERATIONS

The following discussion analyzes significant changes in the results of operations for the three-month, six-month and twelve-month periods ended June 30, 2005, compared to the same periods ended June 30, 2004. The amounts discussed below are on a pre-tax basis unless otherwise noted.

Electric Operating Revenues and Kilowatt-Hour Sales

Of our total electric operating revenues during the second quarter of 2005, approximately 40% were from residential customers, 31% from commercial customers, 18% from industrial customers, 5% from wholesale on-system customers, 2% from wholesale off-system transactions and 4% from miscellaneous sources, primarily transmission services. The breakdown of our customer classes has not significantly changed from the second quarter of 2004.

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

kWh Sales (in millions)

	3 Months Ended 2005	3 Months Ended 2004	% Change*		6 Months Ended 2005	6 Months Ended 2004	% Change*		12 Months Ended 2005	12 Months Ended 2004	% Change*
Residential	386.3	353.5	9.3	%	880.7	852.9	3.3	%	1,731.7	1,747.3	(0.9	)%
Commercial	359.6	344.3	4.5		683.7	674.6	1.3		1,426.4	1,406.2	1.4
Industrial	273.5	274.1	(0.2	)	523.4	528.1	(0.9	)	1,080.7	1,085.1	(0.4	)
Wholesale On-System	79.4	74.7	6.3		154.7	147.9	4.6		312.5	306.1	2.1
Other**	26.4	25.4	3.8		53.4	53.1	0.6		108.4	106.5	1.8
Total On-System	1,125.2	1,072.0	5.0		2,295.9	2,256.6	1.7		4,659.6	4,651.2	0.2

Operating Revenues

($ in millions)

	3 Months Ended 2005***		3 Months Ended 2004		% Change*		6 Months Ended 2005***		6 Months Ended 2004		% Change*		12 Months Ended 2005***		12 Months Ended 2004		% Change*
Residential	$	32.4	$	27.1	19.5	%	$	65.0	$	59.3	9.6	%	$	130.1	$	127.3	2.2	%
Commercial	25.8		22.2		16.0		45.2		41.6		8.6		96.0		91.6		4.8
Industrial	14.9		13.0		15.0		26.1		24.1		8.2		53.8		51.7		4.1
Wholesale On-System	4.0		3.5		17.0		7.5		6.7		12.2		14.4		13.2		8.9
Other**	2.0		1.8		9.4		3.8		3.6		5.9		7.7		7.5		3.6
Total On-System	$	79.1	$	67.6	17.1		$	147.6	$	135.3	9.1		$	302.1	$	291.3	3.7

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

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

On-System Electric Transactions

KWh sales for our on-system customers increased during the second quarter of 2005 over the second quarter of 2004 primarily due to warmer temperatures during 2005 as compared to 2004. Total cooling degree days (the cumulative number of degrees that the average temperature for each day during that period was above 65° F) for the second quarter of 2005 were 14.1% more than the same period last year and 17.3% more than the 20-year average. Revenues for our on-system customers increased approximately $11.6 million. The March 2005 Missouri rate increase and May 2005 Arkansas rate increase (discussed below) contributed an estimated $5.7 million to revenues in the second quarter of 2005 while continued sales growth contributed an estimated $1.8 million. Weather and other related factors contributed an estimated $2.1 million and the collected IEC that is not expected to be refunded contributed approximately $2 million during the second quarter of 2005. Our customer growth was 1.7% in 2004 and 1.6% in 2003. We expect our annual customer growth to range from approximately 1.6% to 1.8% over the next several years, although our customer growth for the twelve months ended June 30, 2005, was 1.9%.

The increase in residential and commercial kWh sales during the second quarter of 2005 was primarily due to the warmer weather conditions with revenues also being positively affected by the March 2005 Missouri rate increase and May 2005 Arkansas rate increase.

Industrial kWh sales, which are not particularly weather sensitive, decreased slightly, mainly due to a decrease in sales to our oil pipeline pumping customers while associated revenues increased for the second quarter of 2005 reflecting the March 2005 Missouri rate increase and May 2005 Arkansas rate increase.

On-system wholesale kWh sales increased during the second quarter of 2005 due mainly to the warmer temperatures and continued sales growth. Revenues associated with these FERC-regulated sales increased more than the kWh sales as a result of the fuel adjustment clause applicable to such sales. This clause permits the distribution to customers of changes in fuel and purchased power costs.

For the six months ended June 30, 2005, kWh sales to our on-system customers increased approximately 1.7% while the associated revenues increased approximately $12.3 million, or 9.1%. Rate increases contributed approximately $6.8 million to revenues with customer growth contributing approximately $3.6 million. The collected IEC that is not expected to be refunded contributed approximately $2.1 million during the six months ended June 30, 2005 while weather and other related factors decreased revenues approximately $0.2 million. KWh sales and related revenues for our residential and commercial customers increased, mainly due to the warmer temperatures in the second quarter of 2005 as compared to the same period in 2004 and to continued sales growth. The increase in residential and commercial revenues during the six months ended June 30, 2005 also reflects the March 2005 Missouri rate increase and the May 2005 Arkansas rate increase. Industrial kWh sales decreased, mainly due to a decrease in sales to our oil pipeline pumping customers while associated revenues increased for the second quarter of 2005 reflecting the March 2005 Missouri rate increase and May 2005 Arkansas rate increase. On-system wholesale kWh sales increased, also reflecting the warmer temperatures in the second quarter of 2005 as compared to the same period in 2004 as well as continued sales growth. Revenues associated with these FERC-regulated sales increased more than the kWh sales as a result of the fuel adjustment clause applicable to such sales.

For the twelve months ended June 30, 2005, kWh sales to our on-system customers increased slightly with the associated revenues increasing approximately $10.7 million. Missouri, Arkansas and Oklahoma rate increases (discussed below) contributed an estimated $7.3 million to revenues and continued sales growth contributed an estimated $8.3 million. Weather and other related factors

offset these increases with an estimated $7.0 million negative impact on revenues while the collected IEC that is not projected to be refunded contributed approximately $2.1 million. Residential kWh sales decreased slightly primarily due to milder temperatures in the first quarter of 2005 and the third and fourth quarters of 2004 as compared to the prior year periods while associated revenues increased reflecting the Missouri, Arkansas and Oklahoma rate increases discussed below. Commercial sales and revenues increased during the twelve months ended June 30, 2005 primarily due to continued sales growth and the Missouri, Arkansas and Oklahoma rate increases. Industrial kWh sales decreased slightly, mainly due to a decrease in sales to our oil pipeline pumping customers during 2005 while associated revenues increased reflecting the Missouri and Arkansas rate increases. On-system wholesale kWh sales and revenues increased for the twelve months ended June 30, 2005 reflecting continued sales growth and the operation of the fuel adjustment clause applicable to these FERC regulated sales.

Rate Matters

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

Jurisdiction	Date Requested	Base Annual Increase Granted		Percent Increase Granted		Date Effective
Arkansas -Electric	July 14, 2004	595,000		7.66	%	May 14, 2005
Missouri - Electric	April 30, 2004	$	25,705,500	9.96	%	March 27, 2005
Oklahoma -Electric	March 4, 2003	766,500		10.99	%	August 1, 2003

On March 4, 2003, we filed a request with the Oklahoma Corporation Commission for an annual increase in base rates for our Oklahoma electric customers in the amount of $954,540, or 12.97%. On August 1, 2003 a Unanimous Stipulation and Agreement was approved by the Oklahoma Corporation Commission providing an annual increase in rates for our Oklahoma customers of approximately $766,500, or 10.99%, effective for bills rendered on or after August 1, 2003. This reflects a rate of return on equity (ROE) of 11.27%.

On April 30, 2004, we filed a request with the MPSC for an annual increase in base rates for our Missouri electric customers in the amount of $38,282,294, or 14.82%. Prior to the hearings, we were able to settle several miscellaneous issues with other parties to the case. On December 22, 2004, we, the MPSC Staff, the Office of the Public Counsel (OPC) and two intervenors filed a unanimous Stipulation and Agreement as to Certain Issues with the MPSC settling several of these issues. One of the issues we were able to agree on was a change in the recognition of pension costs allowing us to defer the Missouri portion of any costs above the amount included in this rate case as a regulatory asset. The amount of pension cost allowed in this rate case was approximately $3 million. This stipulation became effective on March 27, 2005 as part of the final Missouri Order described below. Therefore, the deferral of these costs began in the second quarter of 2005.

The MPSC issued a final order on March 10, 2005 approving an annual increase in base rates of approximately $25.7 million, or 9.96%, effective March 27, 2005. The order granted us a return on equity of 11%, an increase in base rates for fuel and purchased power at $24.68/MWH and an increase in depreciation rates. The new depreciation rates now include a cost of removal component of mass property (transmission, distribution and general plant costs). In addition, the order approved an annual IEC of approximately $8.2 million effective March 27, 2005 and expiring three years later. The IEC is $0.002131 per kilowatt hour of customer usage. The recent extraordinarily high natural gas prices and extreme volatility of natural gas led the MPSC to allow forecasted fuel costs to be used rather than the traditional historical costs in determining the fuel portion of the rate increase. At

the end of two years, an assessment will be made of the money collected from customers compared to the greater of the actual and prudently incurred costs or the base cost of fuel and purchased power set in rates. If the excess of the amount collected over the greater of these two amounts is greater than $10 million, the excess over $10 million will be refunded to the customers. The entire excess amount of IEC, not previously refunded, will be refunded at the end of three years, unless the IEC is terminated earlier. Each refund will include interest at the current prime rate at the time of the refund. The IEC revenues recorded in the second quarter of 2005 did not recover all the Missouri related fuel and purchased power costs incurred in the second quarter of 2005. From inception of the IEC through June 30, 2005, the costs of fuel and purchased power were approximately $2.6 million higher than the total of the costs in our base rates and the IEC recorded during the period. Future recovery of fuel and purchased power costs through the IEC are dependent upon a variety of factors, including natural gas prices, costs of non-contract purchased power, weather conditions, plant availability and coal deliveries.

On March 25, 2005, we, the OPC, the Missouri Industrial Energy Consumers and Intervenors Praxair, Inc. and Explorer Pipeline Company, filed applications with the MPSC requesting the MPSC grant a rehearing with respect to the return on equity granted in the March 2005 Missouri rate case. The MPSC denied these applications on April 7, 2005. We and the OPC have appealed this decision and we each filed initial briefs on June 24, 2005, with the MPSC response brief due August 16, 2005.

On July 14, 2004, we filed a request with the APSC for an annual increase in base rates for our Arkansas electric customers in the amount of $1,428,225, or 22.1%. On May 13, 2005, the APSC granted an annual increase in electric rates for our Arkansas customers of approximately $595,000, or 7.66%, effective May 14, 2005.

On April 29, 2005, we filed a request with the Kansas Corporation Commission for an increase in base rates for our Kansas electric customers in the amount of $4,181,078, or 24.64%. Any new rates approved as a result of this request will not go into effect until the fourth quarter of 2005.

On June 24, 2005, we filed a request with the MPSC for an annual increase in base rates for our Missouri water customers in the amount of $523,000, or 38%. Any new rates approved as a result of this request will not go into effect before 2006.

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

Off-System Electric Transactions

In addition to sales to our own customers, we also sell power to other utilities as available and provide transmission service through our system for transactions between other energy suppliers.

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

	2005						2004
	Three Months Ended		Six Months Ended		Twelve Months Ended		Three Months Ended		Six Months Ended		Twelve Months Ended
(in millions)
Revenues	$	2.5	$	6.8	$	10.7	$	3.4	$	7.0	$	12.6
Expenses	1.7		4.4		6.6		2.1		4.1		7.6
Net	$	0.8	$	2.4	$	4.1	$	1.3	$	2.9	$	5.0

Revenues less expenses decreased for each of the periods reported in 2005 as compared to 2004, reflecting less transmission service revenues for all periods in 2005 as compared to the same

periods in 2004. The expenses in the table above are included in our discussion of purchased power costs below.

Operating Revenue Deductions

During the second quarter of 2005, total operating expenses increased approximately $9.6 million (14.2%) compared with the same period last year. Fuel costs increased approximately $7.3 million (40.7%) but were partially offset by a $0.7 million (5.7%) decrease in purchased power costs during the second quarter of 2005. The increase in fuel costs was primarily due to increased generation by our gas fired units in the second quarter of 2005 (an estimated $4.6 million) combined with higher prices for both hedged and unhedged natural gas that we burned in our gas-fired units (an estimated $2.5 million). Increased coal costs contributed approximately $0.2 million to the total fuel increase. 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 second quarter of 2005 than to purchase power. The net increase in fuel and purchased power during the first quarter of 2005 as compared to the same period last year was $6.6 million (21.7%). We had expected coal costs to increase in the first half of 2005 due to changes in delivered prices resulting from the expiration of our long-term coal and freight contracts. A long-term contract 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 expired in December 2004. We signed a new, three-year contract with Peabody on December 15, 2004 that covers approximately 100% of our anticipated 2005 Western coal requirements, approximately 67% of our anticipated 2006 Western coal requirements and approximately 33% of our anticipated Western coal requirements for 2007. Our prior contract with Union Pacific Railroad Company and The Kansas City Southern Railway Company which provides for transportation of the Powder River Basin coal expired at the end of June 2005. We signed a new, five-year contract with Burlington Northern and Santa Fe Railway Company and The Kansas City Southern Railway Company on April 8, 2005 that became effective June 30, 2005. Although the delivered price of coal under the new contracts was higher than the 2004 price during the second quarter of 2005, we expect the delivered price increase to be substantially mitigated beginning in the third quarter of 2005 due to a combination of our new coal supply and coal transportation contracts.

Regulated – other operating expenses increased approximately $1.0 million (8.1%) during the second quarter of 2005 as compared to the same period in 2004. Expenses relating to our employee health care plan and our employee pension expense contributed approximately $0.5 million and $0.3 million, respectively, to this increase with transmission and distribution expense increasing approximately $0.3 million. These increases in regulated – other operating expense were partially offset by a $0.2 million decrease in general administrative expense due to reduced costs associated with Sarbanes-Oxley Section 404 compliance. As discussed previously, effective with the second quarter of 2005, we began deferring a portion of our pension cost into a regulatory asset as authorized in our latest rate case. We have deferred approximately $0.6 million as of June 30, 2005.

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

Maintenance and repairs expense decreased approximately $0.4 million (6.0%) as compared to the second quarter of 2004 when maintenance costs were up due to generator repairs at the Energy Center.

Depreciation and amortization expense increased approximately $1.5 million (19.7%) during the quarter due to higher depreciation rates that became effective on March 27, 2005, as well as increased plant in service. The provision for income taxes increased approximately $0.5 million during the second quarter of 2005 due to increased income. Our effective federal and state income

tax rate for the second quarter of 2005 was 33.4% as compared to 33.1% for the second quarter of 2004. Other taxes increased approximately $0.4 million (8.3%) during the quarter due to increased property taxes and franchise taxes.

During the six months ended June 30, 2005, total operating expenses were up approximately $13.8 million (10.1%) compared with the same period last year. Fuel costs increased approximately $12.9 million (37.0%) but were partially offset by a $2.7 million (10.1%) decrease in purchased power costs during the period. The increase in fuel costs was primarily due to increased generation by our gas fired units (an estimated $5.6 million) and higher prices for the hedged and unhedged natural gas that we burned in our gas-fired units ($6.4 million) as compared to the first six months of 2004. 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 six months ended June 30, 2005 than to purchase power. The net increase in fuel and purchased power costs during the six months ended June 30, 2005 as compared to the same period last year was $10.3 million (16.7%).

Regulated - other operating expenses for the first six months of 2005 increased approximately $1.5 million (5.7%). Expenses relating to our employee health care plan and our employee pension expense contributed approximately $1.3 million and $1.1 million, respectively, to this increase, offset by a $0.3 million decrease each in stock compensation expense and other power supply expense and a $0.2 million decrease in regulatory commission expense.

Maintenance and repairs expense decreased $0.7 million (6.7%) for the six months ended June 30, 2005 compared to the same period in 2004 primarily due to the $1 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 quarter maintenance costs related to generator repairs at the Energy Center. Depreciation and amortization expense increased approximately $1.9 million (12.4%) during the six-month period due to increased depreciation rates and increased plant in service. Total provisions for income taxes decreased $0.4 million (22.5%) due to decreased taxable income. Our effective federal income tax rate for the first six months of 2005 was 33.4% as compared to 33.5% for the first six months of 2004. Other taxes increased $0.4 million (5.1%) during the six months ended June 30, 2005 due mainly to increased property taxes reflecting our additions to plant in service.

During the twelve months ended June 30, 2005, total operating expenses increased approximately $14.3 million (5.2%) compared to the year ago period. Total fuel costs increased approximately $11.8 million (18.0%) during the twelve months ended June 30, 2005 but were partially offset by a $2.9 million (5.4%) decrease in purchased power costs during the same period. The increase in fuel costs was primarily due to higher prices for both the hedged and unhedged natural gas that we burned in our gas-fired units (an estimated $6.2 million) and increased generation by our gas-fired units (an estimated $5.5 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 June 30, 2005 than to purchase power. The net increase in fuel and purchased power during the twelve months ended June 30, 2005 as compared to the same period last year was $8.9 million (7.5%).

Regulated – other operating expenses increased approximately $2.7 million (5.2%) during the twelve months ended June 30, 2005 as compared to the same period last year due primarily to a $2.0 million increase in employee health care expense, an increase of approximately $1.0 million in employee pension expense and a $0.3 million increase in general administrative expense primarily due to costs associated with Sarbanes-Oxley compliance. These increases in regulated – other operating expense were partially offset by a $0.3 million decrease in transmission and distribution

expense, a $0.4 million decrease in regulatory commission expense and a $0.3 million decrease in professional services.

Maintenance and repairs expense decreased approximately $1.0 million (4.8%) during the twelve months ended June 30, 2005, compared to the year ago period reflecting a decrease of approximately $1.7 million in maintenance costs at the Energy Center compared to the prior year, primarily reflecting the $1 million insurance deductible recorded in the first quarter of 2004 relating to turbine repairs as well as the second quarter maintenance costs related to generator repairs at the Energy Center. This decrease was partially offset by an approximate $0.8 million increase in distribution maintenance costs during the twelve months ended June 30, 2005 as compared to the prior year.

Depreciation and amortization expense increased approximately $2.8 million (9.3%) due to increased depreciation rates and increased plant in service. Provision for income taxes decreased $2.4 million reflecting decreased income during the current period while other taxes increased approximately $1.1 million (6.4%) due to increased property taxes reflecting our additions to plant in service. Our effective federal and state income tax rate for the twelve months ended June 30, 2005 was 34.1% as compared to 34.0% for the same period in 2004.

Non-regulated Items

Our non-regulated businesses, which we operate through our wholly-owned subsidiary EDE Holdings, Inc., include leasing of fiber optics cable and equipment (which we are also using in our own operations), Internet access, close-tolerance custom manufacturing and customer information system software services. We evaluated our non-regulated businesses for impairment at December 31, 2004, updated our analysis at June 30, 2005, and believe, based on this analysis, that no impairment exists based on our forecast of future net cash flows. However, failure to achieve forecasted cash flows could result in impairment in the future.

During the second quarter of 2005, total non-regulated operating revenue and non-regulated operating expense were virtually the same as in the second quarter of 2004.

Our non-regulated businesses generated a $0.5 million net loss in the second quarter of 2005 as compared to a $0.4 million net loss in the second quarter of 2004.

For the six months ended June 30, 2005, total non-regulated operating revenue increased approximately $0.8 million (7.5%) while total non-regulated operating expense increased approximately $0.9 million (7.9%) compared with the same period in 2004. The increase in operating revenue was mainly attributable to MAPP, the close-tolerance custom manufacturing business in which we own a 50.01% interest. The increase in expense was due mainly to the activities of our fiber optics business and to Conversant, a software company in which we own a 100% interest. Conversant markets Customer Watch, an Internet-based customer information system software.

Our non-regulated businesses generated a $0.9 million net loss for the six months ended June 30, 2005 as compared to a $0.8 million net loss for the same period in 2004.

For the twelve-months ended June 30, 2005, total non-regulated operating revenue increased approximately $1.0 million (4.8%) while total non-regulated operating expense increased approximately $2.3 million (10.4%) compared with the same period in 2004. The increase in revenues for the twelve-month-ended period was primarily due to MAPP and our fiber optics business while the increase in expense was primarily due to MAPP, Conversant and our fiber optics business.

Our non-regulated businesses generated a $1.9 million net loss for the twelve-months ended June 30, 2005 as compared to a $1.3 million net loss for the same period in 2004.

Nonoperating Items

Total allowance for funds used during construction (AFUDC) was virtually the same for the second quarter of 2005 as compared to the second quarter of 2004, increased slightly for the six months ended June 30, 2005 and increased $0.2 million during the twelve months ended June 30, 2005 as compared to the prior year period.

Total interest charges on long-term debt decreased $0.2 million for both the second quarter of 2005 and the six months ended June 30, 2005 as compared to the same periods in 2004 and decreased $0.4 million during the twelve months ended June 30, 2005 as compared to the same period in 2004. The decrease for the twelve months ended June 30, 2005 primarily reflects the refinancing we accomplished in 2003 by calling higher interest debt issues and replacing them with debt issues at lower interest rates.

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. 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 the hedged transaction is actually realized or no longer qualifies for hedge accounting.

The following table sets forth the net-of-tax increase/(decrease) and the change in the fair market value (FMV) of our open contracts in Other Comprehensive Income (in millions) for the presented periods ending June 30,:

	3 Months Ended 2005			3 Months Ended 2004			6 Months Ended 2005			6 Months Ended 2004			12 Months Ended 2005			12 Months Ended 2004
Natural gas contracts settled (1)	$	(0.2	)	$	(2.2	)	$	(0.3	)	$	(5.2	)	$	(6.5	)	$	(8.5	)
Interest rate contracts settled	1.4			0.0			1.4			0.0			1.4			(5.1		)
Total contracts settled	$	1.2		$	(2.2	)	$	1.1		$	(5.2	)	$	(5.1	)	$	(13.6	)
Change in FMV of open contracts for natural gas	$	5.7		$	1.1		$	17.6		$	3.6		$	18.2		$	2.7
Change in FMV of open contracts for interest rates	(1.4		)	0.0			(1.4		)	0.0			(1.4		)	4.4
Total change in FMV of contracts	$	4.3		$	1.1		$	16.2		$	3.6		$	16.8		$	7.1
Taxes - natural gas	$	(2.1	)	$	0.4		$	(6.6	)	$	0.6		$	(4.4	)	$	2.2
Taxes – interest rates	0.0			0.0			0.0			0.0			0.0			0.3
Total taxes	$	(2.1	)	$	0.4		$	(6.6	)	$	0.6		$	(4.4	)	$	2.5
Total change in OCI - net of tax	$	3.4		$	(0.7	)	$	10.7		$	(1.0	)	$	7.3		$	(4.0	)

(1) Reflected in fuel expense

Our average cost for our open natural gas hedges increased from $4.567/Dth at March 31, 2005 to $4.703/Dth at June 30, 2005.

Environmental

In mid-December 2003, the EPA issued proposed regulations with respect to SO2, NOx and mercury emissions from coal-fired power plants in a proposed rulemaking known as the Clean Air Interstate Rule (CAIR). The final CAIR was issued by the EPA on March 10, 2005 and will affect 28

states, including Missouri, where our Asbury and Iatan plants are located, but excluding Kansas, where our Riverton plant is located. Also in mid-December 2003, the EPA issued the proposed Clean Air Mercury Rule (CAMR) regulations for mercury emissions by power plants under the requirements of the 1990 Amendments to the Clean Air Act. The final CAMR was issued March 15, 2005. It is possible that we may need to make some expenditures as early as 2007 in order to meet the compliance date of January 1, 2009 for mercury analyzers and the mercury emission compliance date of January 1, 2010. The CAIR and the CAMR were issued as a result of delays and setbacks in the legislative process for the President’s Clear Skies Act legislation, which would have imposed different restrictions on SO2, NOx and mercury emissions. The CAIR and the CAMR are not directed to specific generation units, but instead, require the states (including Missouri and Kansas) to develop State Implementation Plans (SIP) within the next 18 months in order to comply with specific NOx, SO2 and/or mercury state-wide annual budgets (although Kansas is not covered by the NOx or SO2 requirements). Until these plans are finalized, we cannot determine the required emission rates of NOx, SO2 and mercury for the Asbury or Iatan plants in Missouri or the required mercury emission rate for the Riverton plant in Kansas. Also, the SIPs will likely include allowance trading programs for NOx, SO2 and/or mercury that could allow compliance without additional capital expenditures.

As part of our Experimental Regulatory Plan filed with the MPSC, we have committed to install pollution control equipment required at the Iatan plant by 2008 which will include a Selective Catalytic Reduction (SCR) system, a Flue Gas Desulphurization (FGD) system and a Bag House, with our share of the capital cost estimated at $30 million, as previously disclosed. Approximately $17 million of this amount was already included in our capital expenditure budget for equipment to be installed by 2008. Of the remaining amount, $11 million is expected to be incurred in 2007, and is now included in the new capital expenditures budget approved by our Board of Directors on July 28, 2005. For additional information, see “-Liquidity and Capital Resources – Capital Requirements and Investing Activities” below.

As part of our Experimental Regulatory Plan we also committed to add an SCR at Asbury which we expect to be in service before January 2009. We are currently attempting to lay out a schedule to perform the tie-ins with the existing plant during our scheduled 2007 fall outage. Our current cost estimate for an SCR at Asbury is $30 million. We also expect that additional pollution control equipment will be economically justified at the Asbury plant sometime prior to 2015 and may include a FGD and a Bag House at an estimated capital cost of $75 million. At this time we do not anticipate the installation of additional pollution control equipment at the Riverton plant.

LIQUIDITY AND CAPITAL RESOURCES

Cash Provided by Operating Activities

Our net cash flows provided by operating activities increased $6.1 million during the six months ended June 30, 2005 as compared to the six months ended June 30, 2004, despite a $0.7 million decrease in net income. Changes in adjustments to income for non-cash items were $2.3 million higher this year versus last year. In addition, a $4.0 million increase due to reduced working capital requirements (primarily as a result of increased accounts payable and accrued liabilities) positively impacted cash flows.

Capital Requirements and Investing Activities

Our net cash flows used in investing activities increased $22.5 million during the six months ended June 30, 2005 as compared to the six months ended June 30, 2004, primarily reflecting

additions to our transmission and distribution systems and construction expenditures for the new combustion turbine at Riverton.

Our capital expenditures totaled approximately $26.6 million during the second quarter of 2005 compared to approximately $11.9 million for the same period in 2004. For the six months ended June 30, 2005, capital expenditures totaled approximately $42.3 million compared to approximately $19.8 million for the same period in 2004. These capital expenditures include AFUDC, capital expenditures to retire assets and benefits from salvage.

A breakdown of the capital expenditures for the quarter and six months ended June 30, 2005 is as follows:

	Quarter Ended		Six Months Ended
	June 30, 2005		June 30, 2005
	(in millions)
Distribution and transmission system additions	$	10.3	$	18.4
Additions and replacements – Asbury	2.8		3.9
Additions and replacements – Riverton, Iatan, Ozark Beach, Energy Center, State Line and State Line Combined Cycle	1.2		2.0
New generation – Riverton combustion turbine	10.1		14.6
Fiber optics (non-regulated)	0.6		1.1
Transportation	0.0		0.4
New generation – other	0.1		0.3
Other non-regulated capital expenditures	0.2		0.4
Other	0.9		1.8
Retirements and salvage (net)	0.4		(0.6		)
Total	$	26.6	$	42.3

For the first six months of 2005, approximately 44% of our cash requirements for capital expenditures were satisfied internally from operations (funds provided by operating activities less dividends paid). We currently expect that internally generated funds will provide approximately all of the funds required for the remainder of our 2005 capital expenditures. We had originally estimated that our capital expenditures for 2006 and 2007 would be approximately $86.0 million and $88.4 million, respectively (including AFUDC). Due to planned new generation and our proposed Experimental Regulatory Plan, we have revised our estimate of these capital expenditures to approximately $100.4 million for 2006 and $140.9 million for 2007. 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 used in financing activities decreased $18.2 million during the six months ended June 30, 2005 as compared to the six months ended June 30, 2004 resulting in a $1.6 million use of cash in the current year. Our net cash flows used in financing activities were primarily affected by increased proceeds from short-term debt (commercial paper) in 2005 as compared to 2004.

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.

On April 1, 2005, we redeemed our $10 million First Mortgage Bonds, 7.60% Series due April 1, 2005, using short-term debt. On June 27, 2005, we issued $40 million aggregate principal amount of our Senior Notes, 5.8% Series due 2035, for net proceeds of approximately $39.4 million less $0.1 million of legal fees. We used the net proceeds from this issuance to redeem all $30 million aggregate principal amount of our First Mortgage Bonds, 7.75% Series due 2025 for approximately $31.3 million, including interest and a redemption premium, and to repay short-term debt. The $1.2 million redemption premium paid in connection with the redemption of these first mortgage bonds, together with $2.4 million of remaining unamortized loss on reacquired debt and $0.3 million of unamortized debt expense, were recorded as a regulatory asset and are being amortized as interest expense over the life of the 2035 Notes. We had entered into an interest rate derivative contract in May 2005 to hedge against the risk of a rise in interest rates impacting the 2035 Notes prior to their issuance. Costs associated with the interest rate derivative (primarily due to interest rate fluctuations) amounted to approximately $1.4 million and were recorded as a regulatory asset and are being amortized over the life of the 2035 Notes.

We have an effective shelf registration statement with the SEC under which approximately $49 million of our common stock, unsecured debt securities, preference stock and first mortgage bonds remain available for issuance. We are currently planning a new shelf registration for 2005.

Restrictions in our mortgage bond indenture could affect our liquidity. The Mortgage contains a requirement that for new first mortgage bonds to be issued, our net earnings (as defined in the Mortgage) for any twelve consecutive months within the fifteen months preceding issuance must be two times the annual interest requirements (as defined in the Mortgage) on all first mortgage bonds then outstanding and on the prospective issue of new first mortgage bonds. Our earnings for the twelve months ended June 30, 2005 would permit us to issue approximately $448.1 million of new first mortgage bonds based on this test with an assumed interest rate of 6.0%.

As of June 30, 2005, 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+

Moody’s affirmed our ratings on May 13, 2005 and revised their rating outlook on us from negative to stable. On March 14, 2005, Standard & Poor’s, reflecting the MPSC’s March 10, 2005 rate order, affirmed its ‘BBB/A-2’ corporate credit rating on us and removed the rating from credit watch with negative implications. The outlook is now stable. 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 our financing costs will be when our securities are sold. Ratings below investment grade (investment grade is Baa3 or above for Moody’s and BBB- or above for Standard & Poor’s) may also impair our ability to issue short-term debt, commercial paper or other securities or make the marketing of such securities more difficult.

CONTRACTUAL OBLIGATIONS

Set forth below is information summarizing our contractual obligations as of June 30, 2005. Not included in these amounts are expected obligations associated with the installation of the new combustion turbine at Riverton, the wind energy agreement, postretirement benefit funding or any future pension funding commitments.

	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	$	—	$	—	$	70.0	$	288.1
Note payable to securitization trust	50.0		—		—		—		50.0
Interest on long-term debt	438.8		26.0		52.5		49.8		310.5
Capital lease obligations	0.3		0.3		—		—		—
Operating lease obligations	2.4		0.6		1.2		0.6		—
Purchase obligations**	267.8		49.9		86.4		68.9		62.6
Open purchase orders	27.7		16.1		10.3		1.3		—
Other long-term liabilities***	2.8		0.5		2.3		—		—

Total Contractual Obligations	$	1,147.9	$	93.4	$	152.7	$	190.6	$	711.2

*Some of our contractual obligations have price escalations based on economic indices, but we do not anticipate these escalations to be significant.

**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. As of June 30, 2005, EDE Holdings, Inc. was the 50.01% guarantor of a $2.5 million note included in this total amount.

OFF-BALANCE SHEET ARRANGEMENTS

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

CRITICAL ACCOUNTING POLICIES

The March MPSC rate order approved an annual IEC of approximately $8.2 million effective March 27, 2005 and expiring three years later, which allows us to recover Missouri jurisdictional variable fuel and purchased power costs we incur within a range (collar) of $21.97/Mwh (floor) and

$24.11/Mwh (ceiling). The IEC is $0.002131 per kilowatt hour of customer usage. This revenue is recorded by revenue class when service is provided to the customer. If the Missouri variable fuel and purchased power $/Mwh is below the floor, we record a provision for refund of the entire IEC actual recorded dollars. If the Missouri variable fuel and purchased power $/Mwh is above the ceiling, we record all of the IEC collected as revenue. If the Missouri variable fuel and purchased power $/Mwh falls within the collar, the difference between Missouri ceiling dollars and Missouri variable fuel and purchased power dollars will be the provision for refund. The difference between the IEC actual recorded dollars and the provision for refund is the IEC we record as revenue. At each balance sheet date, we evaluate the probability that we would be required to refund either a portion or all of the amounts collected under the IEC to ratepayers.

See “Item 7 – Managements Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report Form 10-K for the year ended December 31, 2004 for a discussion of additional critical accounting policies.

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 financing through our issuance of commercial paper and other short-term debt. We manage our interest rate exposure by limiting our variable-rate exposure (applicable only to commercial paper) 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 2005 than in 2004, our interest expense would increase, and income before taxes would decrease by less than $100,000. This amount has been determined by considering the impact of the hypothetical interest rates on our highest month-end commercial paper balance for 2004. There was $18 million in outstanding commercial paper as of June 30, 2005. 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 a three-year contract for the purchase of coal in order to manage our exposure to fuel prices. We satisfied 70.5% of our 2004 fuel supply need through coal.

Approximately 90% of our 2004 coal supply was Western coal. Our new three-year coal contract satisfies approximately 100% of our anticipated 2005 requirements, approximately 67% of our 2006 requirements and approximately 33% of our anticipated requirements for 2007 for our Asbury and Riverton Western coal needs. Future coal supplies will be acquired using a combination of short-term and long-term contracts.

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. We expect that increases in gas prices will be partially offset by realized gains under financial derivative transactions. As of July 29, 2005, 69.7%, or 2.13 million Dths’s, of our anticipated volume of natural gas usage for the remainder of year 2005 is hedged. See Note 3 of “Notes to Consolidated Financial Statements (Unaudited)” for further information.

Credit Risk. We are exposed to credit risk by our use of derivative financial instruments. Credit risk is the risk that the counterparty might fail to fulfill its performance obligations under contractual terms. Our Risk Management Oversight Committee, which consists of senior management, has adopted credit risk and procedures policies and provides oversight in the monitoring of counterparty creditworthiness.

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 that occurred during the second quarter of 2005 that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.

On April 28, 2005, the Company announced that Laurie A. Delano had been elected to the positions of Assistant Secretary and Assistant Treasurer and that, effective August 1, 2005, Ms. Delano would assume the positions of Controller and Principal Accounting Officer of the Company. Darryl L. Coit, who previously held the positions of Controller, Assistant Secretary, Assistant Treasurer and Principal Accounting Officer announced his retirement effective July 31, 2005.

PART II. OTHER INFORMATION

Item 4. Submission of Matters to a Vote of Security Holders.

(a) The annual meeting of Common Stockholders was held on April 28, 2005.

(b) The following person was re-elected Director of Empire to serve until the 2008 Annual Meeting of Stockholders:

William L. Gipson (21,656,997 votes for; 1,405,638 withheld authority).

The following persons were elected Directors of Empire to serve until the 2008 Annual Meeting of Stockholders:

Bill D. Helton (21,613,405 votes for; 1,449,230 withheld authority).

Kenneth R. Allen (21,639,808 votes for; 1,422,827 withheld authority).

The term of office as Director of the following other Directors continued after the meeting: D. Randy Laney, Mary M. Posner, Ross C. Hartley, Myron W. McKinney, B. Thomas Mueller, Allan T. Thoms and Julio S. Leon.

The following plans were approved by shareholders:

Amendment to the Employee Stock Purchase Plan

Votes For		Votes Against		Abstentions		Broker Non-Votes		Total Shares Present
11,956,804		713,615		305,033		10,087,183		23,062,635

2006 Stock Incentive Plan

Votes For		Votes Against		Abstentions		Broker Non-Votes		Total Shares Present
10,315,454		2,313,264		346,735		10,087,182		23,062,635

Amended and restated Stock Unit Plan for Directors

Votes For		Votes Against		Abstentions		Broker Non-Votes		Total Shares Present
9,548,548		2,934,308		492,596		10,087,183		23,062,635

Item 5. Other Information.

For the twelve months ended June 30, 2005, our ratio of earnings to fixed charges was 2.08x. See Exhibit (12) hereto.

Item 6. Exhibits.

(a) Exhibits.

(4) $150,000,000 Unsecured Credit Agreement, dated as of July 15, 2005, among Empire, UMB Bank, N.A., as administrative agent, Bank of America, N.A., as syndication agent, and the lenders named therein.

(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.*

Part I -	Financial Information (Unaudited):

Item 1.	Consolidated Financial Statements:

	a. Consolidated Statements of Operations

	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

Item 5.	Other Information

Item 6.	Exhibits

Signatures

	THE EMPIRE DISTRICT ELECTRIC COMPANY
	Registrant



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



	By	/s/ Laurie A. Delano
		Laurie A. Delano
		Controller, Assistant Secretary and Assistant Treasurer

August 8, 2005