UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)

x	Quarterly report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
	For the quarterly period ended June 30, 2008 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 (State of Incorporation)	44-0236370 (I.R.S. Employer Identification No.)
602 Joplin Avenue, Joplin, Missouri (Address of principal executive offices)	64801 (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 x No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer o	Accelerated filer x
Non-accelerated filer o (Do not check if a smaller reporting company)	Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes o  No x

As of August 1, 2008, 33,888,354 shares of common stock were outstanding.

THE EMPIRE DISTRICT ELECTRIC COMPANY

INDEX

		PAGE
	Forward Looking Statements	3
Part I -	Financial Information:
Item 1.	Financial Statements:
	a.Consolidated Statements of Operations	4
	b.Consolidated Statements of Comprehensive Income	7
	c.Consolidated Balance Sheets	8
	d.Consolidated Statements of Cash Flows	10
	e.Notes to Consolidated Financial Statements	11
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	30
	Executive Summary	30
	Results of Operations	34
	Rate Matters	44
	Competition	47
	Liquidity and Capital Resources	48
	Contractual Obligations	52
	Dividends	52
	Off-Balance Sheet Arrangements	53
	Critical Accounting Policies.	53
	Recently Issued Accounting Standards.	53
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	53
Item 4.	Controls and Procedures	55
Part II-	Other Information:
Item 1.	Legal Proceedings - (none)
Item 1A.	Risk Factors	55
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	55
Item 5.	Other Information	56
Item 6.	Exhibits	56
	Signatures	57

2

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, potential acquisitions, 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;

·weather, business and economic conditions and other factors which may impact sales volumes and customer growth;

·operation of our electric generation facilities and electric and gas transmission and distribution systems;

·the costs and other impacts resulting from natural disasters, such as tornados and ice storms;

·the periodic revision of our construction and capital expenditure plans and cost estimates;

·legislation;

·regulation, including environmental regulation (such as NOx, SO2 and CO2 regulation);

·competition, including the energy imbalance market;

·electric utility restructuring, including ongoing federal activities and potential state activities;

·the impact of electric deregulation on off-system sales;

·changes in accounting requirements;

·other circumstances affecting anticipated rates, revenues and costs;

·the timing of accretion estimates, and integration costs relating to, completed and contemplated acquisitions and the performance of acquired businesses;

·matters such as the effect of changes in credit ratings on the availability and our cost of funds;

·interruptions or changes in our coal delivery, gas transportation or storage agreements or arrangements;

·the success of efforts to invest in and develop new opportunities;

·costs and effects of legal and administrative proceedings, settlements, investigations and claims; and

·our exposure to the credit risk of our hedging counterparties.

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.

3

PART I.  FINANCIAL INFORMATION

Item 1.  Financial Statements

THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)

	Three Months Ended
	June 30
	2008			2007
	(000’s except per share amounts)
Operating revenues:
Electric	$	100,502		$	97,531
Gas	9,148			8,438
Water	441			454
Other	1,189			826
	111,280			107,249
Operating revenue deductions:
Fuel	24,165			22,189
Purchased power	22,777			19,702
Cost of natural gas sold and transported	5,297			4,722
Regulated operating expenses	17,663			18,211
Other operating expenses	443			492
Maintenance and repairs	6,827			6,234
Depreciation and amortization	13,862			13,082
Provision for income taxes	1,972			2,782
Other taxes	5,948			5,712
	98,954			93,126
Operating income	12,326			14,123
Other income and (deductions):
Allowance for equity funds used during construction	1,497			653
Interest income	543			87
Benefit (provision) for other income taxes	(282		)	11
Other - non-operating expense, net	(224		)	(241		)
	1,534			510
Interest charges:
Long-term debt	8,838			8,060
Note payable to securitization trust	1,062			1,062
Short-term debt	312			314
Allowance for borrowed funds used during construction	(1,514		)	(966		)
Other	345			312
	9,043			8,782
Income from continuing operations	4,817			5,851
Loss from discontinued operations, net of tax	—			(17		)
Net income	$	4,817		$	5,834
Weighted average number of common shares outstanding - basic	33,775			30,384
Weighted average number of common shares outstanding - diluted	33,807			30,406
Earnings from continuing operations per weighted average share of common stock– basic and diluted	$	0.14		$	0.19
Loss from discontinued operations per weighted average share of common stock – basic and diluted	$	—		$	(0.00	)
Total earnings per weighted average share of common stock – basic and diluted	$	0.14		$	0.19
Dividends per share of common stock	$	0.32		$	0.32

See accompanying Notes to Consolidated Financial Statements.

4

	Six Months Ended
	June 30,
	2008			2007
	(000’s except per share amounts)
Operating revenues:
Electric	$	208,806		$	194,441
Gas	36,424			36,028
Water	876			904
Other	2,119			1,526
	248,225			232,899
Operating revenue deductions:
Fuel	55,172			47,413
Purchased power	48,712			39,921
Cost of natural gas sold and transported	22,998			23,444
Regulated operating expenses	35,561			35,574
Other operating expenses	826			835
Maintenance and repairs	12,393			17,012
Depreciation and amortization	27,483			25,780
Provision for income taxes	5,089			4,431
Other taxes	13,106			12,453
	221,340			206,863
Operating income	26,885			26,036
Other income and (deductions):
Allowance for equity funds used during construction	2,615			1,559
Interest income	623			181
Benefit (provision) for other income taxes	(270		)	21
Other - non-operating expense, net	(462		)	(485		)
	2,506			1,276
Interest charges:
Long-term debt	16,911			15,004
Note payable to securitization trust	2,125			2,125
Short-term debt	843			1,342
Allowance for borrowed funds used during construction	(2,862		)	(2,120		)
Other	567			578
	17,584			16,929
Income from continuing operations	11,807			10,383
Loss from discontinued operations, net of tax	—			(48		)
Net income	$	11,807		$	10,335
Weighted average number of common shares outstanding - basic	33,717			30,341
Weighted average number of common shares outstanding - diluted	33,747			30,361
Earnings from continuing operations per weighted average share of common stock– basic and diluted	$	0.35		$	0.34
Loss from discontinued operations per weighted average share of common stock – basic and diluted	$	—		$	(0.00	)
Total earnings per weighted average share of common stock – basic and diluted	$	0.35		$	0.34
Dividends per share of common stock	$	0.64		$	0.64

See accompanying Notes to Consolidated Financial Statements.

5

	Twelve Months Ended
	June 30,
	2008			2007
	(000’s except per share amounts)
Operating revenues:
Electric	$	439,525		$	405,691
Gas	60,273			59,547
Water	1,851			1,893
Other	3,837			2,867
	505,486			469,998
Operating revenue deductions:
Fuel	121,319			97,705
Purchased power	86,463			72,127
Cost of natural gas sold and transported	37,180			37,992
Regulated operating expenses	71,354			68,244
Other operating expenses	1,601			1,556
Maintenance and repairs	27,439			29,804
Loss on plant disallowance	—			828
Gain on sale of assets	(1,241		)	—
Depreciation and amortization	54,302			45,532
Provision for income taxes	15,074			21,184
Other taxes	25,580			23,978
	439,071			398,950
Operating income	66,415			71,048
Other income and (deductions):
Allowance for equity funds used during construction	3,979			2,841
Interest income	768			377
Provision for other income taxes	(319		)	(15		)
Other - non-operating expense, net	(946		)	(1,005		)
	3,482			2,198
Interest charges:
Long-term debt	33,027			28,761
Note payable to securitization trust	4,250			4,250
Short-term debt	2,441			2,366
Allowance for borrowed funds used during construction	(5,484		)	(4,015		)
Other	1,058			1,074
	35,292			32,436
Income from continuing operations	34,605			40,810
Earnings from discontinued operations, net of tax	111			75
Net income	$	34,716		$	40,885
Weighted average number of common shares outstanding – basic	32,265			30,250
Weighted average number of common shares outstanding – diluted	32,294			30,266
Earnings from continuing operations per weighted average share of common stock– basic and diluted	$	1.07		$	1.35
Earnings from discontinued operations per weighted average share of common stock – basic and diluted	$	.01		$	0.00
Total earnings per weighted average share of common stock – basic and diluted	$	1.08		$	1.35
Dividends per share of common stock	$	1.28		$	1.28

See accompanying Notes to Consolidated Financial Statements.

6

THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	Three Months Ended
	June 30,
	2008			2007
	($-000’s)
Net income	$	4,817		$	5,834
Reclassification adjustments for gains included in net income or reclassified to regulatory asset or liability	(1,713		)	(216		)
Net change in fair market value of open derivative contracts for period	22,806			5,731
Income taxes	(8,036		)	(2,101		)
Net change in unrealized gain on derivative contracts	13,057			3,414
Comprehensive income	$	17,874		$	9,248

	Six Months Ended
	June 30,
	2008			2007
	($-000’s)
Net income	$	11,807		$	10,335
Reclassification adjustments for gains included in net income or reclassified to regulatory asset or liability	(2,573		)	(52		)
Net change in fair market value of open derivative contracts for period	33,829			8,611
Income taxes	(11,909		)	(3,261		)
Net change in unrealized gain on derivative contracts	19,347			5,298
Comprehensive income	$	31,154		$	15,633

	Twelve Months Ended
	June 30,
	2008			2007
	($-000’s)
Net income	$	34,716		$	40,885
Reclassification adjustments for gains included in net income  or reclassified to regulatory asset or liability	(4,130		)	(567		)
Net change in fair market value of open derivative contracts for period	30,445			3,380
Income taxes	(10,026		)	(1,072		)
Net change in unrealized gain on derivative contracts	16,289			1,741
Comprehensive income	$	51,005		$	42,626

See accompanying Notes to Consolidated Financial Statements

7

THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS (UNAUDITED)

	June 30, 2008		December 31, 2007
	($-000’s)
Assets
Plant and property, at original cost:
Electric	$	1,465,034	$	1,409,217
Natural gas	55,022		54,715
Water	10,474		10,353
Other	27,480		26,355
Construction work in progress	214,112		167,049
	1,772,122		1,667,689
Accumulated depreciation and amortization	510,656		488,816
	1,261,466		1,178,873
Current assets:
Cash and cash equivalents	3,349		4,043
Accounts receivable – trade, net	37,651		38,011
Accrued unbilled revenues	16,734		20,886
Accounts receivable – other	12,008		15,465
Fuel, materials and supplies	49,040		49,482
Unrealized gain in fair value of derivative contracts	18,228		2,499
Prepaid expenses	3,356		3,308
	140,366		133,694
Noncurrent assets and deferred charges:
Regulatory assets	93,124		92,785
Goodwill	39,492		39,492
Unamortized debt issuance costs	9,443		6,662
Unrealized gain in fair value of derivative contracts	32,269		17,520
Other	3,774		4,048
	178,102		160,507
Total Assets	$	1,579,934	$	1,473,074

(Continued)

See accompanying Notes to Consolidated Financial Statements

8

	June 30, 2008		December 31, 2007
	($-000’s)
Capitalization and Liabilities
Common stock, $1 par value, 33,860,214 and 33,605,871 shares issued and outstanding, respectively	$	33,860	$	33,606
Capital in excess of par value	482,038		477,385
Retained earnings	7,375		17,153
Accumulated other comprehensive income, net of income tax	30,379		11,032
Total common stockholders’ equity	553,652		539,176
Long-term debt:
Note payable to securitization trust	50,000		50,000
Obligations under capital lease	263		349
First mortgage bonds and secured debt	332,930		242,959
Unsecured debt	248,522		248,572
Total long-term debt	631,715		541,880
Total long-term debt and common stockholders’ equity	1,185,367		1,081,056
Current liabilities:
Accounts payable and accrued liabilities	74,358		79,229
Current maturities of long-term debt	155		150
Short-term debt	12,000		33,040
Customer deposits	8,860		8,414
Interest accrued	6,147		5,147
Unrealized loss in fair value of derivative contracts	2,978		1,611
Taxes accrued	9,532		2,931
Current deferred income taxes	6,439		381
	120,469		130,903
Commitments and contingencies (Note 6)
Noncurrent liabilities and deferred credits:
Regulatory liabilities	62,480		58,107
Deferred income taxes	173,677		165,989
Unamortized investment tax credits	3,323		3,441
Pension and other postretirement benefit obligations	14,876		14,115
Unrealized loss in fair value of derivative contracts	454		698
Other	19,288		18,765
	274,098		261,115
Total Capitalization and Liabilities	$	1,579,934	$	1,473,074

See accompanying Notes to Consolidated Financial Statements.

9

THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

	Six Months Ended
	June 30,
	2008			2007
	($-000’s)
Operating activities:
Net income	$	11,807		$	10,335
Adjustments to reconcile net income to cash flows from operating activities:
Depreciation and amortization	29,471			28,675
Pension and other postretirement benefit costs	4,720			4,278
Deferred income taxes and unamortized investment tax credit, net	556			(591		)
Allowance for equity funds used during construction	(2,615		)	(1,559		)
Stock compensation expense	1,543			1,411
Non-cash (gain)/loss on derivatives	(1,705		)	255
Cash flows impacted by changes in:
Accounts receivable and accrued unbilled revenues	11,751			(4,817		)
Fuel, materials and supplies	442			1,557
Prepaid expenses, other current assets and deferred charges	(1,588		)	(4,911		)
Accounts payable and accrued liabilities	4,134			(5,827		)
Customer deposits, interest and taxes accrued	8,101			8,934
Other liabilities and other deferred credits	(496		)	315
Net cash provided by operating activities of continuing operations	66,121			38,055
Net cash provided by operating activities of discontinued operations	—			129
Net cash provided by operating activities	66,121			38,184
Investing activities:
Capital expenditures – regulated	(114,130		)	(83,780		)
Capital expenditures and other investments – other	(919		)	(1,695		)
Proceeds from the sale of property, plant and equipment	807			—
Proceeds from the sale of other business	—			2,500
Net cash used in investing activities of continuing operations	(114,242		)	(82,975		)
Net cash used in investing activities of discontinued operations	—			(7		)
Net cash used in investing activities	(114,242		)	(82,982		)
Financing activities:
Proceeds from first mortgage bonds - electric	89,950			79,831
Long-term debt issuance costs	(907		)	(1,076		)
Debt financing costs	(2,189		)	—
Proceeds from issuance of common stock net of issuance costs	3,366			2,805
Net short-term debt (repayments)	(21,040		)	(27,158		)
Dividends	(21,586		)	(19,424		)
Other	(167		)	(218		)
Net cash provided by financing activities of continuing operations	47,427			34,760
Net cash used in financing activities of discontinued operations	—			(45		)
Net cash provided by financing activities	47,427			34,715
Net decrease in cash and cash equivalents	(694		)	(10,083		)
Cash and cash equivalents at beginning of period	4,043			12,303
Cash and cash equivalents at end of period	$	3,349		$	2,220

See accompanying Notes to Consolidated Financial Statements.

10

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

Note 1 - Summary of Significant Accounting Policies

We operate our businesses as three segments: electric, gas and other. The Empire District Electric Company (EDE), a Kansas corporation organized in 1909, is an operating public utility engaged in the generation, purchase, transmission, distribution and sale of electricity in parts of Missouri, Kansas, Oklahoma and Arkansas. As part of our electric segment, we also provide water service to three towns in Missouri. The Empire District Gas Company (EDG) is our wholly-owned subsidiary formed to hold the Missouri Gas assets acquired from Aquila, Inc. on June 1, 2006. It provides natural gas distribution to communities in northwest, north central and west central Missouri. Our other segment primarily consists of a 100% interest in Empire District Industries Inc., a subsidiary for our fiber optics business. These businesses are held by our wholly-owned subsidiary, EDE Holdings, Inc. (EDE Holdings).

The accompanying interim financial statements do not include all disclosures included in the annual financial statements and therefore should be read in conjunction with the financial statements and notes thereto included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2007.

The information furnished reflects all adjustments, consisting only of normal recurring adjustments, which are in our opinion necessary to state fairly the results for the interim periods as well as present these periods on a consistent basis with the financial statements for the fiscal year ended December 31, 2007. Certain reclassifications have been made to prior year information to conform to the current year presentation.

Note 2 - Recently Issued Accounting Standards

On September 15, 2006, Statement of Financial Accounting Standards (SFAS) No. 157, “Fair Value Measurements,” (FAS 157) was issued. We adopted this statement on January 1, 2008. See Note 13 for the discussion of this adoption and the effect of FASB Staff Position (FSP) 157-2 which amended FAS 157 to delay the effective date for all non-financial assets and liabilities.

On February 15, 2007, the Financial Accounting Standards Board (FASB) issued SFAS No. 159, “The Fair-Value Option for Financial Assets and Financial Liabilities – including an amendment of FAS 115” (FAS 159). Under FAS 159, a company may elect to measure eligible financial assets and financial liabilities at fair value. Unrealized gains and losses on items for which the fair value option has been elected are reported in earnings at each subsequent reporting date. FAS 159 is effective for financial statements issued for fiscal years beginning after November 15, 2007. FAS 159 had no effect on our financial statements.

On April 30, 2007, the FASB issued FASB Staff Position No. 39-1 (FIN 39), an “Amendment of FASB Interpretation No. 39”. FIN 39 is effective for fiscal years ending after November 15, 2007. It amends paragraph 3 of Interpretation 39 to replace the terms “conditional contracts and exchange contracts” with the term “derivative instruments as defined in FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities”. It also amends paragraph 10 of Interpretation 39 to permit a reporting entity to offset fair value amounts recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a payable) against fair value amounts recognized for derivative instruments executed with the same counterparty under the same master netting arrangement that have been offset in accordance with that paragraph. We currently do not apply this offsetting alternative.

On December 1, 2007, the FASB issued SFAS 141(R) “Business Combinations” (FAS 141(R)) and SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51” (FAS 160). FAS 141(R) and FAS 160 are effective for business combinations entered into in fiscal years beginning on or after December 15, 2008. FAS 141(R) changes the definitions of a business and a business combination, and will result in more transactions recorded as business combinations. Certain acquired contingencies will be recorded

11

initially at fair value on the acquisition date, transactions and restructuring costs generally will be expensed as incurred and in partial acquisitions, companies generally will record 100 percent of the assets and liabilities at fair value, including goodwill.

In April 2008, the FASB issued SFAS 161 “Disclosure About Derivative Instruments and Hedging Activities, an Amendment of FASB Statement No. 133” (FAS 161). FAS 161 enhances the current disclosure framework in FAS 133, “Accounting for Derivative Instruments and Hedging Activities.” FAS 161 is effective for periods beginning after November 15, 2008. We do not expect the adoption of FAS 161 to have a material effect on our financial statement disclosures.

See Note 1 under “Notes to Consolidated Financial Statements” in our Annual Report on Form 10-K for the year ended December 31, 2007 for further information regarding recently issued accounting standards.

Note 3– Regulatory Matters

The following table sets forth the components of our regulatory assets and liabilities on our consolidated balance sheet.

Regulatory Assets and Liabilities

(In thousands)	June 30, 2008		December 31, 2007
Regulatory Assets:
Income taxes	$	31,883	$	30,947
Unamortized loss on reacquired debt	14,152		14,813
Unamortized loss on interest rate derivative	2,563		2,719
Asbury five-year maintenance	2,075		2,054
Pension and other postretirement benefits (1)	21,149		22,760
Ice storm costs	16,014		15,518
Asset retirement obligation	3,044		2,971
Other	2,244		1,003
Total	$	93,124	$	92,785

(In thousands)	June 30, 2008		December 31, 2007
Regulatory Liabilities:
Income taxes	$	11,041	$	11,214
Unamortized gain on interest rate derivative	4,306		4,391
Cost of removal	39,099		35,724
Pensions and other postretirement benefits(2)	7,433		5,126
Other	601		1,652
Total	$	62,480	$	58,107

(1) Primarily reflects regulatory assets resulting from the adoption of FAS 158 and regulatory accounting for EDG acquisition costs.

(2) Includes the effect of costs incurred that are more or less than those allowed in rates for the Missouri (EDE and EDG) and Kansas (EDE) portion of pension costs and the Missouri EDE portion of other postretirement benefit costs. Since January 1, 2008, approximately $2.3 million in additional regulatory liabilities and corresponding expense increases have been recognized.

Note 4– Risk Management and Derivative Financial Instruments

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

As of June 30, 2008 and December 31, 2007, we have recorded the following assets and liabilities representing the fair value of derivative financial instruments:

12

Asset Derivatives

		June 30,		December 31,
		2008		2007
(in thousands)	Balance Sheet Classifications	Fair Value		Fair Value
Derivatives designated as hedging
instruments under FAS 133(1)
Natural gas contracts, electric segment	Current assets	$	17,614	$	2,435
	Non-current assets and deferred charges	32,269		17,520
Derivatives not designated as hedging
instruments under FAS 133
Natural gas contracts, gas segment	Current assets	614		64
Total derivative assets		$	50,497	$	20,019

(1)Statement of Financial Accounting Standards (SFAS)No. 133 “Accounting for Derivative Instruments and Hedging Activities” (FAS 133).

Liability Derivatives

		June 30,		December 31,
		2008		2007
(in thousands)	Balance Sheet Classifications	Fair Value		Fair Value
Derivatives designated as hedging
instruments under FAS 133
Natural gas contracts, electric segment	Current liabilities	$	2,330	$	1,154
	Non-current liabilities and deferred charges	93		698
Derivatives not designated as hedging
instruments under FAS 133
Natural gas contracts, gas segment	Current liabilities	648		457
	Non-current liabilities and deferred charges	361		—
Total derivative liabilities		$	3,432	$	2,309

Electric

A $30.4 million net of tax, unrealized gain representing the fair market value of our electric segment derivative contracts treated as cash flow hedges is recognized as Accumulated Other Comprehensive Income in the capitalization section of the balance sheet as of June 30, 2008. The tax effect of $18.7 million on this gain is included in deferred taxes. These amounts will be adjusted cumulatively on a monthly basis during the determination periods, beginning July 1, 2008 and ending on September 30, 2011. As of June 30, 2008, approximately $16.9 million of unrealized gains are applicable to financial instruments which will settle within the next twelve months.

The following table sets forth the actual pre-tax gains/(losses) from the qualified portion of our hedging activities for settled contracts for the electric segment for each of the periods ended June 30:

Derivatives in FAS 133 Cash Flow	Income Statement Classification	Amount of Gain / (Loss) Reclassed from OCI into Income -(Effective portion)
Hedging Relationships	of Gain / (Loss)	Three Months Ended				Six Months Ended				Twelve Months Ended
(in thousands)	on Derivative	2008		2007		2008		2007		2008		2007
Commodity contracts – electric segment	Fuel Expense	$	1,713	$	216	$	2,573	$	52	$	4,130	$	567

We record unrealized gains/(losses) on the ineffective portion of our gas hedging activities in “Fuel” under the Operating Revenue Deductions section of our statement of operations 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 the ineffective portion of our hedging activities for the electric segment for each of the periods ended June 30:

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Derivatives in FAS 133 Cash Flow	Income Statement Classification of	Amount of Gain / (Loss) Recognized in Income on Derivative- (Ineffective)
Hedging Relationships	Gain / (Loss) on	Three Months Ended				Six Months Ended					Twelve Months Ended
(in thousands)	Derivative	2008		2007		2008			2007		2008		2007
Commodity contracts – electric segment	Fuel Expense	$	1	$	40	$	(267	)	$	—	$	14	$	—

The following table sets forth “mark-to-market” pre-tax gains/(losses) from derivatives not designated as hedging instruments under FAS 133 for the electric segment for each of the periods ended June 30:

Derivatives Not Designated as Hedging	Income Statement Classification of	Amount of Gain / (Loss) Recognized in Income on Derivative
Instruments Under FAS 133(1)	Gain / (Loss) on	Three Months Ended				Six Months Ended				Twelve Months Ended
(in thousands)	Derivative	2008		2007		2008		2007		2008		2007
Commodity contracts – electric segment	Fuel Expense	$	—	$	—	$	302	$	—	$	302	$	—

(1) All of our gas hedging activities are related to stabilizing fuel costs as part of our fuel procurement program and are not speculative activities. If conditions change, such as a planned unit outage, we may need to re-designate and/or unwind some of our previous derivatives designated under FAS 133. In this instance, these derivatives would be classified into the category above.

We also enter into fixed-price forward physical contracts for the purchase of natural gas, coal and purchased power. These contracts are not subject to the fair value accounting of FAS 133 because they are considered to be normal purchases. We have instituted a process to determine if any future executed contracts that otherwise qualify for the normal purchases exception contain a price adjustment feature and will account for these contracts accordingly.

As of July 18, 2008, 94% of our anticipated volume of natural gas usage for our electric operations for the remainder of year 2008 is hedged, either through physical or financial contracts, at an average price of $6.895 per Dekatherm (Dth). In addition, the following volumes and percentages of our anticipated volume of natural gas usage for our electric operations for the next five years are hedged at the following average prices per Dth:

Year	% Hedged	Dth Hedged	Average Price
2009	60%	5,161,000	$	6.390
2010	40%	3,740,000	$	6.197
2011	34%	3,200,000	$	5.561
2012	13%	1,200,000	$	7.295
2013	13%	1,200,000	$	7.295

On February 15, 2008, we unwound 992,000 Dths of physical gas contracts originally scheduled for delivery in July and August of 2010 and 2011. This transaction resulted in a gain of approximately $1.3 million after tax which was recorded in the Statement of Operations in the first quarter of 2008. We believe it is probable that we will take physical delivery under the remaining physical gas forward contracts.

Gas

We attempt to mitigate our natural gas price risk for our gas segment by a combination of (1) injecting natural gas into storage during the off-heating season months, (2) purchasing physical forward contracts and (3) purchasing financial derivative contracts. We target to have 95% of our storage capacity full by November 1 for the upcoming winter heating season. As the winter progresses, gas is withdrawn from storage to serve our customers. As of July 17, 2008, we had 0.7 million Dths in storage on the three pipelines that serve our customers. This represents 36% of our storage capacity. Our long-term hedge strategy is to mitigate price volatility for our customers by hedging a minimum of 50% of current year, up to 50% of second year and up to 20% of third year

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expected gas usage by the beginning of the Actual Cost Adjustment (ACA) year at September 1. A Purchased Gas Adjustment (PGA) clause is included in our rates for our gas segment operations, therefore, we mark to market any unrealized gains or losses and any realized gains or losses relating to financial derivative contracts to a regulatory asset or regulatory liability account on our balance sheet.

The following table sets forth “mark-to-market” pre-tax gains / (losses) from financial hedging instruments for the gas segment for each of the periods ended June 30. These gains and losses are recorded to a regulatory asset or liability account due to our commission approved natural gas cost recovery mechanism discussed above.

Derivatives Not Designated as	Balance Sheet Classification of	Amount of Gain / (Loss) Recognized on Balance Sheet
Hedging Instruments Under FAS 133	Gain or (Loss) on	Three Months Ended						Six Months Ended						Twelve Months Ended
(in thousands)	Derivative	2008			2007			2008			2007			2008			2007
Commodity contracts – gas segment	Regulatory assets	$	(395	)	$	(345	)	$	(71	)	$	(311	)	$	(1,262	)	$	(1,894	)

Note 5–Financing

On May 16, 2008, we issued $90 million principal amount of first mortgage bonds. The net proceeds of approximately $89.4 million, less $0.3 million of legal and other financing fees, were added to our general funds and used primarily to pay down short-term indebtedness incurred, in part, as a result of our on-going construction program.

On March 11, 2008, we amended the Indenture of Mortgage and Deed of Trust of The Empire District Electric Company (EDE Mortgage) in order to provide us with additional flexibility to pay dividends to our shareholders by increasing the basket available to pay dividends by $10.75 million. The amendment followed the successful completion of a solicitation of consents from the holders of our First Mortgage Bonds outstanding under the EDE Mortgage. We received consents from holders of 94.46% in aggregate principal amount of the outstanding bonds and paid fees of approximately $1.6 million to the consenting bondholders.

On December 12, 2007, we sold 3,000,000 shares of our common stock in an underwritten public offering for $23.00 per share. The sale resulted in net proceeds of approximately $65.7 million ($69.0 million less issuance costs of $3.3 million). The proceeds were added to our general funds and used to pay down short-term indebtedness incurred, in part, as a result of our on-going construction program.

On July 15, 2005, we entered into a $150 million unsecured revolving credit facility until July 15, 2010. Borrowings (other than through commercial paper) are at the bank’s prime commercial rate or LIBOR plus 100 basis points based on our current credit ratings and the pricing schedule in the line of credit facility. On March 14, 2006, we entered into the First Amended and Restated Unsecured Credit Agreement which amends and restates the $150 million unsecured revolving credit facility. The principal amount of the credit facility was increased to $226 million, with the additional $76 million allocated to support a letter of credit issued in connection with our participation in the Plum Point Energy Station project. This extra $76 million of availability reduces over a four year period in line with the amount of construction expenditures we owe for Plum Point Unit 1 and was $27.5 million as of August 1, 2008. The unallocated credit facility is used for working capital, general corporate purposes and to back-up our use of commercial paper. This facility requires our total indebtedness (which does not include 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 and amortization) 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. As of June 30, 2008, we are in compliance with these ratios. This credit facility is also subject to cross-default if we default on in excess of $10 million in the aggregate on our other indebtedness. This arrangement does not serve to legally restrict the use of our cash in the normal course of

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operations. There were no outstanding borrowings under this agreement at June 30, 2008, however, $12.0 million of the availability thereunder was used at such date to back up our outstanding commercial paper.

Note 6 – Commitments and Contingencies

We are a party to various claims and legal proceedings arising out of the normal course of our business. Management regularly analyzes this information, and has provided accruals for any liabilities, in accordance with the guidelines of Statement of Financial Accounting Standards SFAS 5, “Accounting for Contingencies” (FAS 5). In the opinion of management, it is not probable, given the company’s defenses, that the ultimate outcome of these claims and lawsuits will have a material adverse affect upon our financial condition, or results of operations or cash flows.

Coal, Natural Gas and Transportation Contracts

We have entered into long and short-term agreements to purchase coal and natural gas for our energy supply and natural gas operations. Under these contracts, the natural gas supplies are divided into firm physical commitments and derivatives that are used to hedge future purchases. The firm physical gas and transportation commitments total $46.9 million for July 1, 2008 through June 30, 2009, $45.7 million for July 1, 2009 through June 30, 2011, $44.1 million for July 1, 2011 through June 30, 2013 and $61.4 million for July 1, 2013 and beyond. In the event that this gas cannot be used at our plants, the gas would remain in storage or be liquidated at market price.

We have coal supply agreements and transportation contracts in place to provide for the delivery of coal to the plants. These contracts are written with Force Majeure clauses that enable us to reduce tonnages or cease shipments under certain circumstances or events. These include mechanical or electrical maintenance items, acts of God, war or insurrection, strikes, weather and other disrupting events. This reduces the risk we have for not taking the minimum requirements of fuel under the contracts. Due to the extended Asbury maintenance outage from December 9, 2007 through February 10, 2008, we issued force majeure notices to our Western coal suppliers and to the railroads suspending Western coal shipments during the outage. This relieved us of our contractual obligations to receive shipments of coal to the extent caused by the Asbury outage. The minimum requirements are $26.0 million for July 1, 2008 through June 30, 2009, and $21.0 million for July 1, 2009 through June 30, 2011.

Purchased Power

We currently supplement our on-system generating capacity with purchases of capacity and energy from other utilities in order to meet the demands of our customers and the capacity margins applicable to us under current pooling agreements and National Electric Reliability Council (NERC) rules.

We have contracted with Westar Energy for the purchase of capacity and energy through May 31, 2010. Commitments under this contract total approximately $31.0 million through May 31, 2010.

We also have a long term (30 year) agreement for the purchase of capacity from the Plum Point Energy Station, a new 665-megawatt, coal-fired generating facility which is being built near Osceola, Arkansas. Construction began in the spring of 2006 with completion scheduled for 2010. We have the option to convert the 50 megawatts covered by the purchased power agreement into an ownership interest in 2015. Commitments under this contract total approximately $48.0 million through June 30, 2015.

We have entered into a 20-year purchased power agreement with Cloud County Windfarm, LLC, owned by Horizon Wind Energy, Houston, Texas to purchase the energy generated at the approximately 105-megawatt Phase 1 Meridian Way Wind Farm to be located in Cloud County, Kansas and a 20-year contract with Elk River Windfarm, LLC, owned by IBERDROLA RENEWABLES, Inc. (formerly known as PPM Energy), to purchase the energy generated at the 150-megawatt Elk River Windfarm located in Butler County, Kansas. Although these agreements

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are considered operating leases under Generally Accepted Accounting Principles (GAAP), payments for these wind agreements are recorded as purchased power expenses, and, because of the contingent nature of these payments, are not included in the operating lease obligations discussed below.

New Construction

On March 14, 2006, we entered into contracts to purchase an undivided interest in 50 megawatts of the Plum Point Energy Station’s new 665-megawatt, coal-fired generating facility which is being built near Osceola, Arkansas. The estimated cost is approximately $86.5 million, excluding AFUDC.

On June 13, 2006, we announced we had entered into an agreement with Kansas City Power & Light (KCP&L) to purchase an undivided ownership interest in the coal-fired Iatan 2 generating facility. We will own 12%, or approximately 100 megawatts, of the 850-megawatt unit. Construction began in the spring of 2006 with completion scheduled for 2010. On May 7, 2008, KCP&L announced an update of their estimated construction figures for the construction of the Iatan 2 plant and for the environmental upgrades at the Iatan 1 plant. Our share of the Iatan 2 construction costs will increase from a range of approximately $183.6 million to $200.5 million to a range of approximately $218 million to $230 million. All of these estimated construction expenditures exclude AFUDC. The updated estimate of our share of the cost for environmental upgrades at the Iatan 1 plant is a range of approximately $56 million to $60 million, representing an increase of 22%-30% compared to the previous estimate of approximately $46 million. The in-service date for the Iatan No. 1 project is expected to be February 2009.

A new combustion turbine previously scheduled to be installed by the summer of 2011 will be delayed for at least one year as our generation regulation needs for our purchased power agreements are being met through a combination of our existing units and the SPP energy imbalance market.

Leases

On June 25, 2007, we entered into a 20-year purchased power agreement with Cloud County Windfarm, LLC, owned by Horizon Wind Energy, Houston, Texas. The agreement provides for a 20-year term commencing with the commercial operation date, which is expected to be about January 1, 2009. We will begin taking delivery of the energy at that time. Pursuant to the terms of the agreement, we will purchase all of the output from the approximately 105-megawatt Phase 1 Meridian Way Wind Farm to be located in Cloud County, Kansas. We do not own any portion of the windfarm. Annual payments are contingent upon output of the facility and can range from zero to a maximum of approximately $14.6 million based on a 20-year average cost.

On December 10, 2004, we entered into a 20-year contract with Elk River Windfarm, LLC to purchase the energy generated at the 150-megawatt Elk River Windfarm located in Butler County, Kansas. We have contracted to purchase approximately 550,000 megawatt-hours of energy per year, or approximately 10% of our annual needs, under the contract, which was declared commercial on December 15, 2005. We do not own any portion of the windfarm. Payments for wind energy from the Elk River Windfarm are contingent upon output of the facility. Annual payments can run from zero to a maximum of approximately $16.9 million based on a 20-year average cost.

Payments for these wind agreements are recorded as purchased power expenses, and, because of the contingent nature of these payments, are not included in the operating lease obligations shown below.

We also currently have short-term operating leases for two unit trains to meet coal delivery demands and garage and office facilities for our electric segment and six service center properties for our gas segment. In addition we have a five-year capital lease for telephone equipment.

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Our lease obligations over the next five years are as follows (in thousands):

Capital Leases
2008	$	288
2009	288
2010	100
2011	1
Thereafter	—
Total minimum payments	$	677
Less amount representing maintenance	225
Net minimum lease payments	452
Less amount representing interest	33
Present value of net minimum lease payments	$	419

Operating Leases
2008	$	1,243
2009	373
2010	382
2011	251
2012	185
Thereafter	592
Total minimum payments	$	3,026

The gross amount of assets recorded under capital leases totaled $1.3 million at June 30, 2008. The accumulated amount of amortization for our capital leases was $0.3 million at June 30, 2008.

Environmental Matters

We are subject to various federal, state, and local laws and regulations with respect to air and water quality and with respect to hazardous and toxic materials and wastes, including their identification, transportation, disposal, record-keeping and reporting, as well as other environmental matters. We believe that our operations are in compliance with present laws and regulations.

Electric Segment

Air. The 1990 Amendments to the Clean Air Act, referred to as the 1990 Amendments, affect the Asbury, Riverton, State Line and Iatan Power Plants and Units 3 and 4 (the FT8 peaking units) at the Empire Energy Center. The 1990 Amendments require affected plants to meet certain emission standards, including maximum emission levels for sulfur dioxide (SO2) and nitrogen oxides (NOx).

SO2 Emissions. Under the 1990 Amendments, the amount of SO2 an affected unit can emit is regulated. Each existing affected unit has been allocated a specific number of emission allowances, each of which allows the holder to emit one ton of SO2. Utilities covered by the 1990 Amendments must have emission allowances equal to the number of tons of SO2 emitted during a given year by each of their affected units. The annual reconciliation of allowances, which occurs on a facility wide basis, is held each March 1 for the previous calendar year. Allowances may be traded between plants or utilities or “banked” for future use. A market for the trading of emission allowances exists on the Chicago Board of Trade. The Environmental Protection Agency (EPA) withholds annually a percentage of the emission allowances allocated to each affected unit and sells those emission allowances through a direct auction. We receive compensation from the EPA for the sale of these withheld allowances.

Our Asbury, Riverton and Iatan coal plants burn a blend of low sulfur Western coal (Powder River Basin) and higher sulfur blend coal and petroleum coke, or burn 100% low sulfur Western coal. In addition, tire-derived fuel (TDF) is used as a supplemental fuel at the Asbury Plant. The

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Riverton Plant can also burn natural gas as its primary fuel. The State Line Plant, the Energy Center Units 3 and 4 and Riverton Unit 12 are gas-fired facilities and do not receive SO2 allowances. In the near term, annual allowance requirements for the State Line Plant, the Energy Center Units 3 and 4 and Riverton Unit 12, which are not expected to exceed 20 allowances per year, will be transferred from our inventoried bank of allowances. In 2007, the combined actual SO2 allowance need for all affected plant facilities exceeded the number of allowances allocated to us by the EPA. Based on our March 1, 2008 EPA reconciliation, we had approximately 24,000 banked SO2 allowances at December 31, 2007 as compared to 31,000 at December 31, 2006. We project that our 2008 emissions will again exceed the number of allowances allocated by the EPA by an amount approximately equal to the difference during 2007.

When our SO2 allowance bank is exhausted, we will need to purchase additional SO2 allowances or build a Flue Gas Desulphurization (FGD) scrubber system at our Asbury Plant. Based on current and projected SO2 allowance prices and high-level estimated FGD scrubber construction costs ($81 million in 2010 dollars), we expect it will be more economical for us to purchase SO2 allowances than to build a scrubber at the Asbury Plant. We would expect the costs of SO2 allowances to be fully recoverable in our rates.

On July 14, 2004, we filed an application with the MPSC seeking an order authorizing us to implement a plan for the management, sale, exchange, transfer or other disposition of our SO2 emission allowances issued by the EPA. On March 1, 2005, the MPSC approved a Stipulation and Agreement granting us authority to manage our SO2 allowance inventory in accordance with our SO2 Allowance Management Policy (SAMP). The SAMP allows us to swap banked allowances for future vintage allowances and/or monetary value and, in extreme market conditions, to sell SO2 allowances outright for monetary value. The Stipulation and Agreement became effective March 11, 2005, although we have not yet swapped or sold any allowances. Our banked allowances are not assigned a cost value. The allowances are removed from inventory on a FIFO basis.

NOx Emissions. The Asbury, Iatan, State Line, Energy Center and Riverton Plants are each in compliance with the NOx limits applicable to them under the 1990 Amendments as currently operated.

The Asbury Plant received permission from the Missouri Department of Natural Resources (MDNR) to burn TDF at a maximum rate of 2% of total fuel input. During 2007, approximately 2,651 tons of TDF were burned. This is equivalent to 265,100 discarded passenger car tires.

Under the MDNR’s Missouri NOx Rule, our Iatan, Asbury, State Line and Energy Center facilities, like other facilities in Western Missouri, are generally subject to a maximum NOx emission rate of 0.35 lbs/MMBtu during the ozone season of May 1 through September 30. However, facilities which burn at least 100,000 passenger tire equivalents of TDF per year, including our Asbury Plant, are subject to a higher NOx emission limit of 0.68 lbs/MMBtu. All of our plants currently meet the required emission limits and additional NOx controls are not required at this time.

In March 2008, the EPA lowered the National Ambient Air Quality Standard (NAAQS) for ozone from 84 ppb to 75 ppb. Ozone, also called ground level smog, is formed by the mixing of NOx and Volatile Organic Compounds (VOCs) in the presence of sunlight. It is possible that most of southwest Missouri will be classified as non-attainment or non-classified by the EPA in 2010 or later. We anticipate that the EPA will classify the Kansas City area, where Iatan 1 is located, as non-attainment in 2010. At this time we do not foresee the need for additional pollution controls due to the ozone reduction. In addition, our units do not emit appreciable VOCs. We do not anticipate that southeast Kansas will be classified as non-attainment under the new ozone NAAQS.

Clean Air Interstate Rule (CAIR)

The EPA issued its final CAIR on March 10, 2005. CAIR governed NOx and SO2 emissions from fossil fueled units greater than 25 megawatts in 28 states, including Missouri, where our Asbury, Energy Center, State Line and Iatan Plants are located and Arkansas where the Plum Point Energy Station is being constructed. Kansas was not included in CAIR and our Riverton Plant was not affected. The CAIR was not directed to specific generation units, but instead, required the states

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(including Missouri and Arkansas) to develop specific State Implementation Plans (SIPS) to comply with specific NOx and SO2 state-wide annual budgets.

On July 11, 2008, the U.S. Court of Appeals for the District of Columbia Circuit vacated the CAIR Rule and remanded it back to the EPA. It is not known at this time how the remand will affect us until CAIR has been finally adjudicated.

The EPA must decide whether it will appeal the ruling, modify CAIR to address the vacated issues, rescind CAIR or replace CAIR. Missouri and Arkansas submitted CAIR SIPS to the EPA. These SIPS were approved and remain in effect until the EPA provides guidance to the states regarding the U.S. Court of Appeals ruling. No guidance has yet been issued by the EPA or the states of Missouri and Arkansas.

CAIR would have regulated SO2 by increasing the 1990 Amendments to the Clean Air Act surrender rate of 1 allowance for 1 ton of SO2 emissions to 2:1 in 2010 and 2.86:1 in 2015.

If the CAIR rulemaking is ultimately revoked by the EPA, and, subsequently, the states rescind their SIPS, the Clean Air Visibility Rule which includes Best Available Retrofit Technology (BART) requirement re-emerges under current law. Missouri had adopted CAIR as the mechanism to comply with BART. Kansas had adopted a specific BART plan, but Riverton is not considered a BART facility in the Kansas plan.

In order to help meet previously anticipated CAIR requirements and to meet air permit requirements for Iatan Unit 2, pollution control equipment is being installed on Iatan Unit 1 with the in-service date expected to be February 2009. This equipment includes a Selective Catalytic Reduction (SCR) system, an FGD scrubber and a baghouse, with our share of the capital cost estimated to be between $56 million and $60 million, excluding AFUDC. Of this amount, approximately $3.9 million was incurred in 2006 and $12.1 million in 2007 with estimated expenditures of approximately $25.7 million in 2008 and $17.5 million in 2009. This project was also included as part of our Experimental Regulatory Plan approved by the MPSC.

Also to help meet previously anticipated CAIR requirements and the existing Missouri NOx Rule, we constructed an SCR at Asbury that was completed in November 2007 and placed in service in February 2008 at a total cost of approximately $31.0 million (excluding AFUDC), of which $28.1 million was expended through December 31, 2007 with the remainder expended in 2008. This project was also included as part of our Experimental Regulatory Plan approved by the MPSC.

Clean Air Mercury Rule (CAMR)

On March 15, 2005, the EPA issued the CAMR regulations for mercury emissions by power plants under the requirements of the 1990 Amendments to the Clean Air Act. The new mercury emission limits for Phase 1 were scheduled to go into effect January 1, 2010 and remain in effect until January 1, 2018. Beginning January 1, 2018, more restrictive mercury emission limits were scheduled to go into effect for Phase 2 of CAMR. These regulations were challenged in the U.S. Court of Appeals for the District of Columbia Circuit by a group of states led by New Jersey. On February 8, 2008, the Court of Appeals issued its opinion and vacated the EPA’s CAMR regulations. The EPA is required to reconsider the regulation of mercury under Section 112 of the 1990 Amendments.

The EPA has not yet issued guidance to the states regarding the vacated regulation and recommended future actions. Based on CAMR, we installed a mercury analyzer at Asbury during late 2007 and scheduled the installation of two mercury analyzers at Riverton during 2008 in order to verify our mercury emissions and to meet the compliance date of January 1, 2009 for mercury analyzers and the Phase 1 mercury emission compliance date of January 1, 2010. We will complete the installation of the mercury analyzers at Riverton in anticipation of future mercury regulations.

After being finally adjudicated, if the CAMR rulemaking is ultimately revoked by the EPA, Maximum Achievable Control Technology (MACT) re-emerges under current law. No specific MACT rulemakings have yet been adopted in Missouri or Kansas.

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CO2 Emissions

Our coal and gas plants emit carbon dioxide (CO2), a greenhouse gas. Although not currently regulated, increasing public concern and political pressure from local, regional, national and international bodies may result in the passage of new laws mandating limits on greenhouse gas emissions such as CO2. Several bills addressing climate change have been introduced in the U.S. Congress and, in April 2007, the U.S. Supreme Court issued a decision ruling the EPA improperly declined to address CO2 impacts in a rule-making related to new motor vehicle emissions. While this decision is not directly applicable to power plant emissions, the reasoning of the decision could affect other regulatory programs. Various proposals in the U.S. Congress could require us to purchase offsets or allowances for some or all of our CO2 emissions, or otherwise affect us based on the amount of CO2 we generate. The impact on us of any future greenhouse gas regulation will depend in large part on the details of the requirements and the timetable for mandatory compliance.

Water. We operate under the Kansas and Missouri Water Pollution Plans that were implemented in response to the Federal Water Pollution Control Act Amendments of 1972. The Asbury, Iatan, Riverton, Energy Center and State Line plants are in compliance with applicable regulations and have received discharge permits and subsequent renewals as required. The State Line permit was renewed in May 2007. The Energy Center permit was renewed in September 2005 and the Asbury Plant permit was renewed in December 2005.

The Riverton Plant is affected by final regulations for Cooling Water Intake Structures issued under the Clean Water Act (CWA) Section 316(b) Phase II. The regulations became final on February 16, 2004 and required the submission of a Sampling Report and Comprehensive Demonstration Study with the permit renewal in 2008. A Proposal for Information Collection (PIC) was approved by the Kansas Department of Health and Environment (KDHE). Aquatic sampling commenced in April 2006 in accordance with the PIC and was completed in August 2007. Analysis of the sampling and summary reports was completed during the first quarter of 2008 and submitted to the KDHE. These reports indicate that the effect of the cooling water intake structure on Empire Lake’s aquatic life is insignificant. The need for a further Demonstration Study is not expected. On January 25, 2007, the United States Court of Appeals for the Second Circuit remanded key sections of the EPA’s February 16, 2004 regulations. On July 9, 2007, the EPA suspended the regulation and is expected to revise and re-propose the regulation by December 2008. We will monitor the EPA revision process and comment appropriately. In addition, on April 14, 2008 certiorari was granted by the United States Supreme Court limited to the review as to whether Section 316(b) of the CWA authorized the EPA to compare costs with benefits in determining the best technology available for minimizing adverse environmental impacts at cooling water intake structures. The permit renewal application was prepared and submitted in June 2008. Under the initial 316(b) regulations, we did not expect costs associated with compliance to be material. We will reassess costs after the Supreme Court issues its ruling and the revised rules are complete.

Other. Under Title V of the 1990 Amendments, we must obtain site operating permits for each of our plants from the authorities in the state in which the plant is located. These permits, which are valid for five years, regulate the plant site’s total air emissions; including emissions from stacks, individual pieces of equipment, road dust, coal dust and other emissions. We have been issued permits for Asbury, Iatan, Riverton, State Line and the Energy Center Plants. We submitted the required renewal applications for the State Line and Energy Center Title V permits in 2003 and the Asbury Title V permit in 2004 and will operate under the existing permits until the MDNR issues the renewed permits. A Compliance Assurance Monitoring (CAM) plan will be required by the renewed permit for Asbury. We estimate that the capital costs associated with the CAM plan will not exceed $2 million.

A new air permit was issued for the Iatan Generating Station on January 31, 2006. The new permit covers the entire Iatan Generating Station and includes the existing Unit No. 1 and Iatan Unit No. 2 currently under construction. The new permit limits Unit No. 1 to a maximum of 6,600 MMBtu per hour of heat input. The 6,600 MMBtu per hour heat input limit is in effect until the new SCR, scrubber, and baghouse are completed, currently estimated to be in February of 2009.

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Gas Segment

The acquisition of Missouri Gas involved the property transfer of two former manufactured gas plant (MGP) sites previously owned by Aquila, Inc. and its predecessors. Site #1 is listed in the MDNR Registry of Confirmed Abandoned or Uncontrolled Hazardous Waste Disposal Sites in Missouri. Site #2 has received a letter of no further action from the MDNR. A Change of Use request and work plan was approved by the MDNR allowing us to expand our existing service center at Site #1 in Chillicothe, Missouri. This project, which was completed in October 2007, included the removal of all excavated soil and the addition of a new concrete surface replacing the existing gravel at a cost of approximately $0.1 million. We estimate further remediation costs at these two sites to be no more than approximately $0.2 million, based on our best estimate at this time. This estimated liability is recorded under noncurrent liabilities and deferred credits. In our agreement with the MPSC approving the acquisition of Missouri Gas, it was agreed that we could reflect a liability and offsetting regulatory asset not to exceed $260,000 for the acquired sites. The MPSC agreed that up to $260,000 of costs related to the clean up of these MGP sites would be allowed for future rate recovery. Accordingly, we concluded that rate recovery was probable and at the acquisition date, a regulatory asset of $260,000 was recorded as part of the purchase price allocation based on our agreement with the MPSC, and in accordance with Statement of Financial Accounting Standards No. 71 – “Accounting for the Effects of Certain Types of Regulation” (FAS 71).

Note 7 – Retirement Benefits

Net periodic benefit pension cost, some of which is capitalized as a component of labor cost and some of which is deferred as a regulatory asset, is comprised of the following components (in thousands):

	Three months ended June 30,
	Pension Benefits						SERP						Other Postretirement Benefits
	2008			2007			2008			2007			2008			2007
Service cost	$	863		$	875		$	12		$	13		$	407		$	525
Interest cost	2,245			2,044			32			29			910			975
Expected return on plan assets	(2,680		)	(2,588		)	—			—			(938		)	(825		)
Amortization of prior service cost (1)	186			94			(2		)	(3		)	(253		)	(125		)
Amortization of net actuarial loss (1)	404			650			30			37			140			300
Net periodic benefit cost	$	1,018		$	1,075		$	72		$	76		$	266		$	850

	Six months ended June 30,
	Pension Benefits						SERP						Other Postretirement Benefits
	2008			2007			2008			2007			2008			2007
Service cost	$	1,725		$	1,750		$	24		$	25		$	814		$	1,050
Interest cost	4,491			4,087			63			59			1,820			1,950
Expected return on plan assets	(5,359		)	(5,175		)	—			—			(1,876		)	(1,650		)
Amortization of prior service cost (1)	372			188			(4		)	(6		)	(505		)	(250		)
Amortization of net actuarial loss (1)	807			1,300			61			73			279			600
Net periodic benefit cost	$	2,036		$	2,150		$	144		$	151		$	532		$	1,700

	Twelve months ended June 30,
	Pension Benefits						SERP						Other Postretirement Benefits
	2008			2007			2008			2007			2008			2007
Service cost	$	3,468		$	3,385		$	49		$	49		$	1,468		$	1,915
Interest cost	8,641			7,991			122			111			3,287			3,714
Expected return on plan assets	(10,484		)	(10,208		)	—			—			(3,624		)	(3,076		)
Amortization of prior service cost (1)	772			434			(10		)	(5		)	(1,266		)	(512		)
Amortization of net actuarial loss (1)	2,108			2,970			134			146			831			1,798
Net periodic benefit cost	$	4,505		$	4,572		$	295		$	301		$	696		$	3,839

(1) 2007 and 2008 amounts are amortized from our regulatory asset recorded upon adoption of FAS 158.

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Based on the performance of our pension plan assets through January 1, 2007 and 2008, we were not required by law to fund any additional minimum Employee Retirement Income Security Act of 1974 (ERISA) amounts with respect to 2007 or 2008.

We expect to make other postretirement benefit contributions of $1.1 million in 2008, of which $0.9 million has been made as of June 30, 2008.

Note 8 – Stock-Based Awards and Programs

We recognized the following amounts in compensation expense and tax benefits for all of our stock-based awards and programs for the applicable periods ended June 30:

	Three Months Ended				Six Months Ended				Twelve Months Ended
(in thousands)	2008		2007		2008		2007		2008		2007
Compensation Expense	$	503	$	513	$	1,377	$	1,266	$	2,234	$	1,997
Tax Benefit Recognized	181		187		505		465		813		726

Activity for our various stock plans for the six months ended June 30, 2008 is summarized below:

Performance-Based Restricted Stock Awards

The fair value of the estimated shares to be awarded under the 2008 grant of restricted stock was estimated on the date of grant using a Monte Carlo option valuation model. The 2007 grant was estimated on the date of grant using a lattice-based option valuation model. The assumptions used in each model are noted in the following table:

	2008	2007
Risk-free interest rate	2.44%	5.09% to 4.88%
Expected volatility of Empire stock	19.9%	16.6%
Expected volatility of peer group stock	20.3%	18.9%
Expected dividend yield on Empire stock	5.4%	5.55%
Expected forfeiture rates	3%	3%
Plan cycle	3 years	3 years
EDE percentile performance	24th	25th
Fair value percentage	113.0%	107.73%
Grant date	1/30/2008	1/31/2007
Grant date fair value per share	$24.78	$25.65

                Non-vested restricted stock awards (based on target number) as of June 30, 2008 and 2007 and changes during the six months ended June 30, 2008 and 2007 were as follows:

	YTD 2008				YTD 2007
	Number of shares		Weighted Average Grant Date Price		Number of shares		Weighted Average Grant Date Price
Nonvested at January 1,	43,400		$	23.02	38,800		$	22.25
Granted	21,000		$	21.92	17,700		$	23.81
Awarded	(6,486	)	$	22.77	(7,598	)	$	21.79
Not Awarded	(5,614	)			(5,502	)
Nonvested at June 30,	52,300		$	22.64	43,400		$	23.02

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At June 30, 2008, there was $0.7 million of total unrecognized compensation cost related to estimated outstanding awards. This cost will be recognized over the outstanding years remaining in the vesting period.

Stock Options

A summary of option activity under the plan during the six months ended June 30, 2008 and 2007 is presented below:

	2008			2007
		Weighted				Weighted
		Average				Average
		Exercise				Exercise
	Options	Price		Options		Price
Outstanding at January 1,	149,200	$	23.04	135,000		$	22.21
Granted	56,400	$	21.92	64,200		$	23.83
Exercised	—			(50,000	)	$	21.79
Outstanding at June 30,	205,600	$	22.73	149,200		$	23.04
Exercisable at June 30,	43,300	$	22.67	4,200		$	21.79

The aggregate intrinsic value at June 30, 2008 was $0. The aggregate intrinsic value at June 30, 2007 was less than $0.1 million. The intrinsic value of the unexercised options is the difference between Empire’s closing stock price on the last day of the quarter and the exercise price multiplied by the number of in the money options had all option holders exercised their option on the last day of the quarter. The intrinsic value is zero if such closing price is less than the exercise price.

The range of exercise prices for the options outstanding at June 30, 2008 was $21.79 to $23.81. The weighted-average remaining contractual life of outstanding options at June 30, 2008 and 2007 was 7.6 years and 8.1 years, respectively. As of June 30, 2008, there was $0.4 million of total unrecognized compensation expense related to the non-vested options granted under the plan. That cost will be recognized over a period of 1 to 3 years.

	Stock Options
	2008			2007
Weighted average fair value of grants	$	2.42		$	2.38
Risk-free interest rate	3.38		%	4.68		%
Dividend yield	5.40		%	5.33		%
Expected volatility	20.0		%	16.13		%
Expected life in months	78			60
Grant Date	1/30/08			1/31/07

Employee Stock Purchase Plan

Our Employee Stock Purchase Plan (ESPP) permits the grant to eligible employees of options to purchase common stock at 90% of the lower of market value at date of grant or at date of exercise. The lookback feature of this plan is valued at 90% of the Black-Scholes methodology plus 10% of the maximum subscription price. As of June 30, 2008, there were 442,009 shares available for issuance in this plan. The adoption of FAS 123(R) did not change the valuation of the options granted under this plan.

	2008			2007
Subscriptions outstanding at June 30	49,960			42,578
Maximum subscription price	$	18.57	(1)	$	21.23
Shares of stock issued	38,803			37,686
Stock issuance price	$	18.61		$	20.05

(1) Stock will be issued on the closing date of the purchase period, which runs from June 1, 2008 to May 31, 2009.

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Assumptions for valuation of these shares are shown in the table below.

ESPP

	2008			2007
Weighted average fair value of grants	$	3.46		$	3.40
Risk-free interest rate	2.17		%	4.98		%
Dividend yield	6.20		%	5.43		%
Expected volatility	26.00		%	18.01		%
Expected life in months	12			12
Grant Date	6/2/08			6/1/07

Note 9 - Regulated Operating Expenses

The following table sets forth the major components comprising “Regulated operating expenses” under “Operating Revenue Deductions” on our consolidated statements of operations (in thousands) for all periods presented ended June 30:

	Three Months Ended		Three Months Ended		Six Months Ended		Six Months Ended		Twelve Months Ended		Twelve Months Ended
	2008		2007		2008		2007		2008		2007
Electric transmission and distribution expense	$	2,687	$	2,314	$	5,344	$	4,379	$	10,432	$	8,755
Natural gas transmission and distribution expense	475		425		949		868		1,836		1,788
Power operation expense (other than fuel)	2,716		2,625		5,429		4,984		10,861		9,976
Customer accounts and assistance expense	2,439		2,222		4,987		4,340		9,845		8,933
Employee pension expense (1)	1,568		1,574		3,122		3,390		6,285		5,790
Employee healthcare plan (1)	1,944		2,428		3,887		4,205		7,581		8,199
General office supplies and expense	2,400		2,602		4,842		5,168		9,968		9,405
Administrative and general expense	2,555		2,709		5,551		5,574		11,090		11,603
Allowance for uncollectible accounts	879		1,312		1,450		2,666		3,456		3,795
Total	$	17,663	$	18,211	$	35,561	$	35,574	$	71,354	$	68,244

(1) Includes effects of regulatory treatment for pension and other postretirement benefits but does not include capitalized portion or amount deferred to a regulatory asset.

Note 10 – Segment Information

We operate our business as three segments:  electric, gas and other. As part of our electric segment, we also provide water service to three towns in Missouri. EDG is our wholly owned subsidiary formed to hold the Missouri Gas assets acquired from Aquila, Inc. on June 1, 2006. The other segment consists primarily of a subsidiary for our fiber optics business.

In August 2006, we sold our controlling 52% interest in MAPP, a company that specialized in close-tolerance custom manufacturing for the aerospace, electronics, telecommunications and machinery industries. In December 2006, we sold our 100% interest in Conversant, Inc., a software company that marketed Customer Watch, an Internet-based customer information system software. On September 28, 2007, we sold our 100% interest in Fast Freedom, Inc., an Internet service provider. For financial reporting purposes, MAPP, Conversant and Fast Freedom, all of which were formerly within our other segment, have been classified as discontinued operations and are not included in our segment information.

The tables below present statement of income information, balance sheet information and capital expenditures of our business segments.

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	For the quarter ended June 30, 2008
($-000’s)	Electric		Gas			Other		Eliminations			Total
Statement of Income Information
Revenues	$	100,943	$	9,148		$	1,321	$	(132	)	$	111,280
Depreciation and amortization	13,055		481			326		—			13,862
Federal and state income taxes	2,467		(403		)	190		—			2,254
Operating income	11,713		261			352		—			12,326
Interest income	552		149			—		(158		)	543
Interest expense	9,680		991			44		(158		)	10,557
Income from AFUDC (debt and equity)	3,011		—			—		—			3,011
Income (loss) from continuing operations	5,157		(648		)	308		—			4,817
Capital Expenditures	$	48,579	$	453		$	667				$	49,699

	For the quarter ended June 30, 2007
($-000’s)	Electric		Gas			Other			Eliminations			Total
Statement of Income Information
Revenues	$	97,984	$	8,438		$	923		$	(96	)	$	107,249
Depreciation and amortization	12,369		471			242			—			13,082
Federal and state income taxes	3,235		(469		)	5			—			2,771
Operating income	13,859		97			167			—			14,123
Interest income	256		147			—			(316		)	87
Interest expense	8,916		976			172			(316		)	9,748
Income from AFUDC (debt and equity)	1,618		1			—			—			1,619
Income (loss) from continuing operations	6,592		(736		)	(5		)	—			5,851
Capital Expenditures	$	40,149	$	469		$	1,118		—			$	41,736

	For the six months ended June 30, 2008
($-000’s)	Electric		Gas		Other		Eliminations			Total
Statement of Income Information
Revenues	$	209,682	$	36,424	$	2,382	$	(263	)	$	248,225
Depreciation and amortization	25,874		961		648		—			27,483
Federal and state income taxes	3,955		1,106		298		—			5,359
Operating income	22,659		3,639		587		—			26,885
Interest income	655		264		—		(296		)	623
Interest expense	18,658		1,981		103		(296		)	20,446
Income from AFUDC (debt and equity)	5,476		1		—		—			5,477
Income from continuing operations	9,516		1,806		485		—			11,807
Capital Expenditures	$	102,826	$	890	$	1,082				$	104,798

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	For the six months ended June 30, 2007
($-000’s)	Electric		Gas		Other		Eliminations			Total
Statement of Income Information
Revenues	$	195,345	$	36,028	$	1,719	$	(193	)	$	232,899
Depreciation and amortization	24,364		938		478		—			25,780
Federal and state income taxes	3,807		582		21		—			4,410
Operating income	22,976		2,702		358		—			26,036
Interest income	522		185		—		(526		)	181
Interest expense	17,274		1,963		338		(526		)	19,049
Income from AFUDC (debt and equity)	3,665		14		—		—			3,679
Income from continuing operations	9,436		926		21		—			10,383
Capital Expenditures	$	88,056	$	733	$	1,811				$	90,600

	For the twelve months ended June 30, 2008
($-000’s)	Electric		Gas		Other		Eliminations			Total
Statement of Income Information
Revenues	$	441,376	$	60,273	$	4,344	$	(507	)	$	505,486
Depreciation and amortization	51,147		1,912		1,243		—			54,302
Federal and state income taxes	13,739		1,095		559		—			15,393
Operating income	59,904		5,626		885		—			66,415
Interest income	695		454		—		(381		)	768
Interest expense	37,166		3,974		17		(381		)	40,776
Income from AFUDC (debt and equity)	9,459		4		—		—			9,463
Income from continuing operations	31,916		1,849		840		—			34,605
Capital Expenditures	$	203,316	$	2,180	$	4,277				$	209,773

	For the twelve months ended June 30, 2007
($-000’s)	Electric		Gas		Other			Eliminations			Total
Statement of Income Information
Revenues	$	407,583	$	59,547	$	3,254		$	(386	)	$	469,998
Depreciation and amortization	42,756		1,851		925			—			45,532
Federal and state income taxes	21,027		190		(18		)	—			21,199
Operating income	66,271		4,035		742						71,048
Interest income	1,257		223		—			(1,103		)	377
Interest expense	32,737		3,986		832			(1,103		)	36,452
Income from AFUDC (debt and equity)	6,783		73		—			—			6,856
Income (loss) from continuing operations	40,565		336		(91		)				40,810
Capital Expenditures(1)	$	152,100	$	1,356	$	2,502					$	155,958

	As of June 30, 2008
($-000’s)	Electric		Gas(1)		Other		Elimination			Total
Balance Sheet Information
Total assets	$	1,513,525	$	124,141	$	22,529	$	(80,261	)	$	1,579,934

(1) Includes goodwill of $39,492

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	As of December 31, 2007
($-000’s)	Electric		Gas(1)		Other		Elimination			Total
Balance Sheet Information
Total assets	$	1,395,289	$	121,918	$	22,101	$	(66,234	)	$	1,473,074

(1) Includes goodwill of $39,492.

Note 11 – Discontinued Operations

In August 2006, we sold our controlling 52% interest in MAPP, a company that specialized in close-tolerance custom manufacturing for the aerospace, electronics, telecommunications and machinery industries. In December 2006, we sold our 100% interest in Conversant, Inc., a software company that marketed Customer Watch, an Internet-based customer information system software. On September 28, 2007, we sold our 100% interest in Fast Freedom, Inc., an Internet service provider. We have reported MAPP, Conversant and Fast Freedom’s results as discontinued operations. A summary of the components of gains or losses from discontinued operations for all periods reported as of June 30, follows:

	For the three months ended June 30, 2007
($-000’s)	Fast Freedom			Total
Revenues	$	310		$	310
Expenses	337			337
Losses from discontinued operations before income taxes	(27		)	(27		)
Income tax	10			10
Minority interest	—			—
Income tax – minority interest	—			—
Loss from discontinued operations	$	(17	)	$	(17	)

	For the six months ended June 30, 2007
($ -000’s)	Fast Freedom			Total
Revenues	$	622		$	622
Expenses	699			699
Losses from discontinued operations before income taxes	(77		)	(77		)
Income tax	29			29
Minority interest	—			—
Income tax – minority interest	—			—
Loss from discontinued operations	$	(48	)	$	(48	)

	For the twelve months ended June 30, 2008
($-000’s)	Fast Freedom			Total
Revenues	$	282		$	282
Expenses	103			103
Earnings from discontinued operations before income taxes	179			179
Income tax	(68		)	(68		)
Minority interest	—			—
Income tax – minority interest	—			—
Gain from discontinued operations	$	111		$	111

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	For the twelve months ended June 30, 2007
($-000’s)	MAPP			Conversant			Fast Freedom			Total
Revenues	$	1,904		$	883		$	1,301		$	4,088
Expenses	2,040			1,815			1,513			5,368
Losses from discontinued operations before income taxes	(136		)	(932		)	(212		)	(1,280		)
Gain on disposal	272			555			—			827
Income tax	52			355			81			488
Minority interest	65			—			—			65
Income tax – minority interest	(25		)	—			—			(25		)
Gain (loss) from discontinued operations	$	228		$	(22	)	$	(131	)	$	75

Note 12– FAS 157 – Fair Value Measurements

In September 2006, Statement of Financial Accounting Standards (SFAS) No. 157, “Fair Value Measurements,” (FAS 157) was issued. This statement defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles and expands disclosures about fair value measurements. This statement applies under other accounting pronouncements that require or permit fair value measurements. FASB Staff Position (FSP) 157-1, issued in February 2008, amended FAS 157 to exclude FASB Statement No. 13, “Accounting for Leases” (FAS 13) and other FAS 157 accounting pronouncements that address fair value measurements for purposes of lease classification or measurement under FAS 13. FASB Staff Position (FSP) 157-2 amended FAS 157 to delay the effective date of FAS 157 for all nonfinancial assets and nonfinancial liabilities to fiscal years beginning after November 15, 2008.

The adoption of FAS 157 for financial assets and financial liabilities, effective January 1, 2008 did not have a material impact on our consolidated financial position, results of operations and cash flows. We are evaluating the effect the adoption of FAS 157 for nonfinancial assets and nonfinancial liabilities will have on our consolidated financial position, results of operations and cash flows.

FAS 157 establishes a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value. These tiers include: (i) Level 1, defined as quoted prices in active markets for identical instruments; (ii) Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and (iii) Level 3, defined as unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions.

The following fair value hierarchy table presents information about our assets measured at fair value using the market value approach on a recurring basis as of June 30, 2008:

	Fair Value Measurements at Reporting Date Using
($ in 000’s) Description	As of 6/30/08		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Net derivative assets*	$	47,065	$	10,957	$	36,108	—
Cash and cash equivalents	1,477		1,477		—		—

*The only recurring liabilities are derivative related and are netted against the asset amounts shown in the table above.

We did not have any gains or losses for valuation using significant unobservable inputs.

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Note 13– Income Taxes

We adopted the provisions of FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes,” on January 1, 2007. We decreased our estimate of unrecognized tax benefits during the quarter ended March 31, 2008 as a review of certain amended returns by the Joint Committee on Taxation was completed. The Joint Committee accepted our tax position which led us to recognize certain tax benefits previously unrecognized. We do not expect any significant changes to our unrecognized tax benefits over the next twelve months. The reserve balance related to unrecognized tax benefits as of June 30, 2008 and December 31, 2007 was $219,000 and $328,000, respectively.

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

EXECUTIVE SUMMARY

We operate our businesses as three segments: electric, gas and other. The Empire District Electric Company (EDE) is an operating public utility engaged in the generation, purchase, transmission, distribution and sale of electricity in parts of Missouri, Kansas, Oklahoma and Arkansas. As part of our electric segment, we also provide water service to three towns in Missouri. The Empire District Gas Company (EDG) is our wholly owned subsidiary formed to hold the Missouri Gas assets acquired from Aquila, Inc. on June 1, 2006. It provides natural gas distribution to customers in 44 communities in northwest, north central and west central Missouri. Our other segment consists primarily of our fiber optics business. During the twelve months ended June 30 2008, 87.3% of our gross operating revenues were provided from sales from our electric segment (including 0.4% from the sale of water), 11.9% from our gas segment and 0.8% from our other segment.

In August 2006, we sold our controlling 52% interest in Mid-America Precision Products (MAPP), which specialized in close-tolerance custom manufacturing. In December 2006, we sold our 100% interest in Conversant, Inc., a software company that marketed Customer Watch, an Internet-based customer information system software. On September 28, 2007, we sold our 100% interest in Fast Freedom, Inc., an Internet service provider. For financial reporting purposes, MAPP, Conversant and Fast Freedom, all of which were formerly within our other segment, have been classified as discontinued operations and are not included in our segment information.

Electric Segment

The primary drivers of our electric operating revenues in any period are: (1) rates we can charge our customers, (2) weather, (3) customer growth and (4) general economic conditions. The utility commissions in the states in which we operate, as well as the Federal Energy Regulatory Commission (FERC), set the rates which we can charge our customers. In order to offset expenses, we depend on our ability to receive adequate and timely recovery of our costs (primarily fuel and purchased power) and/or rate relief. We assess the need for rate relief in all of the jurisdictions we serve and file for such relief when necessary. Weather affects the demand for electricity. Very hot summers and very cold winters increase electric 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 by general economic conditions. Customer growth, which is the growth in the number of customers, contributes to the demand for electricity. We expect our annual electric customer growth to range from approximately 1.4% to 1.6% over the next several years. Our electric customer growth for the twelve months ended June 30, 2008 was 0.7%. We define electric sales growth to be growth in kWh sales period over period excluding the impact of weather. The primary drivers of electric sales growth are customer growth and general economic conditions.

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The primary drivers of our electric operating expenses in any period are: (1) fuel and purchased power expense, (2) maintenance and repairs expense, including repairs following severe weather and plant outages, (3) taxes and (4) 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 for electric generation and purchased power, we have entered into long and short-term agreements to purchase power (including wind energy) and coal and natural gas for our energy supply. We currently engage in hedging activities in an effort to minimize our risk from volatile natural gas prices.

Gas Segment

The primary drivers of our gas operating revenues in any period are: (1) rates we can charge our customers, (2) weather, (3) customer growth, (4) the cost of natural gas and interstate pipeline transportation charges and (5) general economic conditions. The MPSC sets the rates which we can charge our customers. In order to offset expenses, we depend on our ability to receive adequate and timely recovery of our costs (primarily commodity natural gas) and/or rate relief. We assess the need for rate relief and file for such relief when necessary. However, as part of the unanimous stipulation and agreement filed with the MPSC on March 1, 2006 and approved on April 18, 2006, we have agreed to not file a rate increase request for non-gas costs prior to June 1, 2009. A PGA clause is included in our gas rates, which allows us to recover our actual cost of natural gas from customers through rate changes, which are made periodically (up to four times) throughout the year in response to weather conditions, natural gas costs and supply demands. Weather affects the demand for natural gas. Very cold winters increase demand for gas, while mild weather reduces demand. Due to the seasonal nature of the gas business, revenues and earnings are typically concentrated in the November through March period, which generally corresponds with the heating season. Customer growth, which is the growth in the number of customers, contributes to the demand for gas. Our gas segment customer contraction for the twelve months ended June 30, 2008 was 4.1%, which we believe was due to higher gas prices and general economic conditions. We expect our annual gas customer growth to be up to 1% over the next several years. We define gas sales growth to be growth in mcf sales excluding the impact of weather. The primary drivers of gas sales growth are customer growth and general economic conditions.

The primary driver of our gas operating expense in any period is the price of natural gas. However, because gas purchase costs for our gas utility operations are normally recovered from our customers, any change in gas prices does not have a corresponding impact on income unless such costs are deemed imprudent or causes customers to reduce usage.

Earnings

During the second quarter of 2008, basic and diluted earnings per weighted average share of common stock were $0.14 as compared to $0.19 in the second quarter of 2007. For the six months ended June 30, 2008, basic and diluted earnings per weighted average share of common stock were $0.35 as compared to $0.34 for the six months ended June 30, 2007. For the twelve months ended June 30, 2008, basic and diluted earnings per weighted average share of common stock were $1.08 as compared to $1.35 for the twelve months ended June 30, 2007. As reflected in the table below, the primary positive driver for all periods presented was increased electric revenues, while increased total electric fuel and purchased power costs was the primary negative driver for all periods presented. Increased depreciation was also a negative driver for all periods presented but primarily for the twelve months ended June 30, 2008 mainly due to $5.1 million of regulatory amortization related to the December 21, 2006 Missouri rate order that has been recorded as depreciation expense during this twelve-month period.

The following reconciliation of basic earnings per share between the three months, six months and twelve months ended June 30, 2007 versus June 30, 2008 is a non-GAAP presentation. We believe this information is useful in understanding the fluctuation in earnings per share between the prior and current years. The reconciliation presents the after tax impact of significant items and

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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, 2007 and 2008 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 – 2007	$	0.19		$	0.34		$	1.35
Revenues
Electric on-system	$	(0.01	)	$	0.15		$	0.42
Electric off – system and other	0.08			0.18			0.31
Gas	0.02			0.01			0.01
Water	—			—			—
Other	0.01			0.01			0.02
Expenses
Electric fuel	(0.04		)	(0.18		)	(0.51		)
Purchased power	(0.07		)	(0.20		)	(0.31		)
Cost of natural gas sold and transported	(0.01		)	0.01			0.02
Regulated – electric segment	0.01			(0.01		)	(0.08		)
Regulated –gas segment	—			0.01			0.01
Maintenance and repairs	(0.01		)	0.11			0.05
Depreciation and amortization	(0.02		)	(0.04		)	(0.19		)
Other taxes	(0.01		)	(0.02		)	(0.03		)
Interest charges	(0.02		)	(0.03		)	(0.09		)
AFUDC	0.03			0.04			0.05
Loss on plant allowance	—			—			0.02
Gain on sale of assets	—			—			0.03
Change in effective income tax rates	—			(0.01		)	0.05
Other income and deductions	—			0.01			0.01
Dilutive effect of additional shares issued in December 2007	(0.01		)	(0.03		)	(0.06		)
Earnings Per Share – 2008	$	0.14		$	0.35		$	1.08

Recent Activities

Financing

On May 16, 2008, we issued $90 million principal amount of first mortgage bonds. The net proceeds of approximately $89.4 million, less $0.3 million of legal and other financing fees, were added to our general funds and used primarily to pay down short-term indebtedness incurred, in part, as a result of our on-going construction program.

Amendment of EDE Mortgage

On March 11, 2008, we amended the Indenture of Mortgage and Deed of Trust of The Empire District Electric Company (EDE Mortgage) in order to provide us with additional flexibility to pay dividends to our shareholders by increasing the basket available to pay dividends by $10.75 million. The amendment followed the successful completion of a solicitation of consents from the holders of our First Mortgage Bonds outstanding under the EDE Mortgage. We received consents from holders of 94.46% in aggregate principal amount of the outstanding bonds and paid fees of approximately $1.6 million to the consenting bondholders. See “— Dividends” below.

Asbury SCR and Maintenance Outage

We constructed an SCR at Asbury that was completed in November 2007 and placed in service in February 2008. The total cost of the SCR project was approximately $31.0 million

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(excluding AFUDC), of which $28.1 million was expended through December 31, 2007 with the remainder expended in 2008. This project was also included as part of our Experimental Regulatory Plan approved by the MPSC. We combined this project with our five year Asbury maintenance outage.

Our Asbury units went off-line September 21, 2007 and were expected to be back on-line during the last week of November, during which time we expected to tie in the SCR. However, on December 7, 2007, during the reassembly of the generator, the unit failed inspection. On December 9, 2007 it was determined that corrective action would be necessary and that additional work would require the unit to remain on outage an additional 60 days. The unit was returned to service on February 10, 2008. We had to replace the energy that would have been generated by our coal-fired units at the Asbury plant with energy generated at our gas plants and with purchased power. After assessing the actual cost of the incremental purchased power and gas-fired generation, we estimate the planned outage added incremental expenses of approximately $8.7 million for the fourth quarter of 2007. We estimate the extended outage increased expenses an additional $3.5 million in the fourth quarter of 2007 (December 8-December 31, 2007) and an additional $5.8 million in the first quarter of 2008 (January 1-February 10, 2008).

Regulatory Matters

On October 1, 2007, we filed a request with the MPSC for an annual increase in base rates for our Missouri electric customers in the amount of $34.7 million, or 10.11%. We requested recovery of our investment in the new 150-megawatt combustion turbine, Unit 12, at our Riverton plant, capital expenditures associated with the construction of a selective catalytic reduction system at our Asbury Plant, capital expenditures and expenses related to the January and December 2007 ice storms and other changes in our underlying costs. We also requested implementation of a fuel adjustment clause in Missouri which would permit the distribution to Missouri customers of changes in fuel and purchased power costs.

The MPSC issued an order on July 30, 2008, effective August 9, 2008, granting an annual increase in base rates for Missouri electric customers in the amount of $22.0 million, or 6.7%, based on a 10.8% return on equity. We anticipate that the new rates will go into effect by September 1, 2008. The order contains two components. The first component provides an addition to base rates of approximately $27.7 million. This increase in base rates was partially offset by a $5.7 million downward adjustment to regulatory amortization, which is the second component. Regulatory amortization provides us additional cash through rates during the current construction cycle. This construction, which is part of our long-range plan to ensure reliability, includes the facilities at the Riverton Power Plant and Iatan 2 Power Plant, as well as environmental improvements at the Asbury Power Plant and at Iatan 1. The regulatory amortization is now approximately $4.5 million. The MPSC also authorized a fuel adjustment clause for our Missouri customers. The MPSC established a base rate for the recovery of fuel and purchased power expenses used to supply energy and the clause permits the distribution to customers of 95% of the changes in fuel and purchased power costs above or below the base. Rates related to the fuel adjustment clause will be modified twice a year subject to the review and approval by the MPSC. The MPSC also approved the Stipulations and Agreements providing for the recovery of deferred expenses for the 2007 ice storms and continuation of the pension and other post-retirement employee benefits trackers established in our 2006 Missouri rate case. The MPSC order also established a two-way tracker, which allows us to defer the amount over and under the cost of compliance to a regulatory asset or liability, for the cost of compliance with the vegetation and infrastructure reliability rules adopted by the MPSC which had an effective date of July 2008.

With regard to our 2006 Missouri rate case, on March 19, 2007, the Office of Public Counsel (OPC) filed a Petition for Writ of Mandamus with the Missouri Supreme Court seeking an order requiring the Missouri Public Service Commission (MPSC) to vacate and rescind its December 29, 2006 order approving tariffs and directing the MPSC to provide an effective date for any subsequent tariff approval order that allows at least ten days to prepare and file an application for rehearing. On October 30, 2007, the Supreme Court issued an opinion directing the MPSC to vacate its December 29 order approving tariffs and allow the OPC a reasonable time to prepare and file an application for

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rehearing. The Court did not examine the lawfulness or reasonableness of the substance of the MPSC’s December 29, 2006 order approving tariffs, and considered only the timing of the issuance of the order. The Court also did not consider the underlying tariffed rates which continue in force and in effect.

Acting upon the opinion of the Missouri Supreme Court, the MPSC issued an order on December 4, 2007, effective December 14, 2007, vacating the December 29, 2006 order and re-approving the tariffs and the same resulting increase in rates. The OPC and intervenors Praxair, Inc. and Explorer Pipeline Company, filed applications for rehearing with the MPSC regarding this order. These applications for rehearing remain pending before the MPSC.

On March 26, 2008, the MPSC issued its Order Granting Reconsideration of Report and Order, to be effective April 5, 2008, and its Report and Order Upon Reconsideration, to be effective April 5, 2008, in which the MPSC made additional findings and reaffirmed the rate increase originally authorized in December of 2006. In this order, the MPSC made two adjustments. An increase in the return on rate base was offset by a decrease in the regulatory amortization from $10.4 million to $10.2 million. The OPC and intervenors Praxair and Explorer Pipeline filed applications for rehearing regarding this Report and Order Upon Reconsideration. These applications for rehearing remain pending before the MPSC.

Also with regard to the 2006 Missouri rate case, on March 18, 2008, the OPC filed a Petition for Writ of Mandamus with the Missouri Supreme Court to force the MPSC to comply with the Missouri Supreme Court’s opinion and order of October 30, 2007. The OPC, the MPSC, the intervenors and Empire have filed written briefs and made oral arguments.

We filed applications for Accounting Authority Orders in Oklahoma and Kansas and filed a request for storm recovery in Arkansas respecting costs incurred due to the two major ice storms in 2007. On May 23, 2008, the Arkansas Public Service Commission issued an Order allowing us to defer approximately $0.4 million of extraordinary incremental expenses incurred as a result of the 2007 ice storms as a regulatory asset and amortize such costs over a 5 year period beginning with the first full month following the storms. On June 24, 2008, the State Corporation Commission of the State of Kansas issued an Order approving our application for an accounting order to accumulate and defer for recovery in future rate case proceedings, approximately $1.1 million of 2007 ice storm costs as a regulatory asset to be amortized over a 10-year period. On June 25, 2008, the Corporation Commission of Oklahoma issued a Final Order approving a Joint Stipulation and Settlement Agreement giving us permission to defer and record approximately $0.5 million of 2007 ice storm costs as a regulatory asset and authorizing recovery of the regulatory asset over a five year period, via a rider effective July 1, 2008. We were granted rate recovery of the Missouri ice storm costs as part of the order issued by the MPSC on July 30, 2008 as discussed above.

For additional information, see “Rate Matters” below.

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, 2008, compared to the same periods ended June 30, 2007.

The following table represents our results of operations by operating segment for the applicable periods ended June 30:

	Quarter Ended						Six Months Ended				Twelve Months Ended
(in millions)	2008			2007			2008		2007		2008		2007
Income from continuing operations
Electric	$	5.2		$	6.6		$	9.5	$	9.4	$	31.9	$	40.6
Gas	(0.6		)	(0.8		)	1.8		0.9		1.8		0.3
Other	0.3			0.0			0.5		0.0		0.9		(0.1		)
Income from continuing operations	$	4.8		$	5.8		$	11.8	$	10.3	$	34.6	$	40.8
Income from discontinued operations	—			—			—		—		0.1		0.1
Net income	$	4.8		$	5.8		$	11.8	$	10.3	$	34.7	$	40.9

*Differences could occur due to rounding.

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Electric Segment

Overview

Our electric segment income from continuing operations for the second quarter of 2008 was $5.2 million as compared to $6.6 million for the second quarter of 2007.

Electric segment operating revenues comprised approximately 90.7% of our total operating revenues during the second quarter of 2008. Of our total electric operating revenues during the second quarter of 2008, approximately 36.2% were from residential customers, 31.5% from commercial customers, 16.5% from industrial customers, 4.4% from wholesale on-system customers, 7.3% from wholesale off-system transactions and 4.1% from miscellaneous sources, primarily public authorities. The percentage of revenues provided from our wholesale off-system transactions has increased during the second quarter of 2008 as compared to the second quarter of 2007, primarily due to sales facilitated by the SPP Energy Imbalance Services (EIS) market that began on February 1, 2007.

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 for the applicable periods ended June 30, were as follows:

	kWh Sales (in millions)				kWh Sales (in millions)				kWh Sales (in millions)
	Second	Second			6 Months	6 Months			12 Months	12 Months
	Quarter	Quarter	%		Ended	Ended	%		Ended	Ended	%
(in millions)	2008	2007	Change*		2008	2007	Change*		2008	2007	Change*
Residential	381.6	378.7	0.8	%	975.1	923.9	5.5	%	1,981.7	1,956.3	1.3	%
Commercial	392.5	398.4	(1.5	)	771.4	756.1	2.0		1,626.1	1,601.0	1.6
Industrial	269.5	289.5	(6.9	)	531.6	544.9	(2.4	)	1,097.0	1,135.5	(3.4	)
Wholesale On-System	83.7	82.5	1.4		169.1	162.7	3.9		348.8	339.0	2.9
Other**	30.0	27.6	8.8		62.0	55.7	11.5		123.1	115.3	6.8
Total On-System	1,157.3	1,176.7	(1.6	)	2,509.2	2,443.3	2.7		5,176.7	5,147.1	0.6

	Operating Revenues ($ in millions)						Operating Revenues ($ in millions)						Operating Revenues ($ in millions)
	Second		Second				6 Months		6 Months				12 Months		12 Months
	Quarter		Quarter		%		Ended		Ended		%		Ended		Ended		%
($ in millions)	2008		2007		Change*		2008		2007		Change*		2008		2007		Change*
Residential	$	36.3	$	36.2	0.2	%	$	85.0	$	80.9	5.0	%	$	178.6	$	169.5	5.4	%
Commercial	31.7		32.0		(0.9	)	59.6		58.3		2.2		130.3		123.7		5.3
Industrial	16.6		17.4		(4.8	)	31.4		31.9		(1.5	)	67.2		66.5		1.1
Wholesale On-System	4.4		4.3		4.1		9.5		8.6		11.0		19.4		17.5		10.5
Other**	2.6		2.3		11.4		5.2		4.6		13.2		10.7		9.5		12.5
Total On-System	$	91.6	$	92.2	(0.6	)	$	190.7	$	184.3	3.5		$	406.2	$	386.7	5.0

*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.

Quarter Ended June 30, 2008 Compared to Quarter Ended June 30, 2007

On-System Operating Revenues and Kilowatt-Hour Sales

KWh sales for our on-system customers decreased during the second quarter of 2008 as compared to the second quarter of 2007. Revenues for our on-system customers decreased approximately $0.6 million, or 0.6%. Weather and other related factors decreased revenues by an estimated $2.5 million compared to last year’s second quarter. 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 2008 were 32.7% less than the same period last year and 4.2% less than the 30-year average. Partially offsetting these factors were sales growth, which

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contributed an estimated $0.9 million during the second quarter of 2008, and rate changes which contributed an estimated $1.0 million.

Residential kWh sales and related revenues increased slightly during the second quarter of 2008, primarily as a result of sales growth, despite unusually rainy weather during the second quarter of 2008 as compared with 2007.

Commercial and industrial kWh sales and revenues decreased for the second quarter of 2008 as compared to the same period in 2007 mainly due to overall economic conditions.

On-system wholesale kWh sales increased during the second quarter of 2008 reflecting customer growth. Revenues associated with these FERC-regulated sales increased more than 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.

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. See “— Competition” below. The following table sets forth information regarding these sales and related expenses for the applicable periods ended June 30:

	2008		2007
	Three Months		Three Months
(in millions)	Ended		Ended
Revenues	$	7.9	$	4.4
Expenses	5.6		3.3
Net*	$	2.3	$	1.1

*Differences could occur due to rounding.

Revenues increased during the second quarter of 2008 as compared to the second quarter of 2007, primarily due to sales facilitated by the SPP EIS market that began on February 1, 2007. Sales from this market contributed $4.3 million to our off-system electric revenues in the second quarter of 2008 with $2.7 million of related expense as compared to $1.4 million of electric revenues in the second quarter of 2007 with $1.2 million of related expense. Total purchase power related expenses are included in our discussion of purchased power costs below.

Operating Revenue Deductions

During the second quarter of 2008, total electric segment operating expenses increased approximately $5.1 million (6.1%) compared with the same period last year. Purchased power costs increased approximately $3.1 million (15.6%) during the second quarter of 2008 while total fuel costs increased approximately $2.0 million (8.9%). This combined increase in fuel and purchased power expenses of $5.1 million (12.1%) included increased costs for off-system sales of $2.3 million. In addition, the effect of replacement power for an outage at one of our small coal units (Riverton 8) partially drove these increased costs. We estimate the effect of this outage to be approximately $1.8 million. The increase in purchased power costs was primarily due to higher prices. Total fuel costs increased primarily due to higher prices for both the hedged and unhedged natural gas that we burned in our gas-fired units in the second quarter of 2008 (an estimated $3.0 million). Increased coal generation contributed an estimated $1.0 million to total fuel costs in the second quarter of 2008 as compared to the second quarter of 2007 when there were outages at the Iatan and Asbury plants. Increased coal costs contributed an estimated $0.3 million. These increased costs were partially offset by decreased generation from our gas-fired units (an estimated $2.1 million) mainly due to an extended spring maintenance outage at the State Line Combined Cycle plant (SLCC) in April and May of 2008 while other fuel costs decreased approximately $0.3 million.

Regulated operating expenses for our electric segment decreased approximately $0.6 million (3.5%) during the second quarter of 2008 as compared to the same period in 2007 primarily due to

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decreases of $0.4 million in employee health care expense, $0.3 million in uncollectible accounts expense and $0.1 million in injuries and damages expense. These decreases were partially offset by an increase of $0.4 million in transmission and distribution expense.

Maintenance and repairs expense increased approximately $0.8 million (13.8%) in the second quarter of 2008 as compared to 2007 primarily due to increases of $0.4 million in maintenance and repairs expense at the SLCC plant related to the extended spring maintenance outage in the second quarter of 2008, $0.3 million in distribution maintenance expense, primarily related to increased tree trimming efforts and second quarter 2008 tornado damage, and $0.2 million in maintenance expense at the Riverton plant due to an extended outage on Unit 8 to repair damage to high pressure blades discovered during Riverton’s five–year maintenance outage in May 2008. These increases were partially offset by a $0.3 million decrease in maintenance expense at the Asbury plant.

Depreciation and amortization expense increased approximately $0.7 million (5.6%) during the quarter mainly due to increased plant in service. Other taxes increased approximately $0.1 million during the second quarter of 2008 due to increased property tax reflecting our additions to plant in service and municipal franchise taxes.

Six Months Ended June 30, 2008 Compared to Six Months Ended June 30, 2007

On-System Operating Revenues and Kilowatt-Hour Sales

KWh sales for our on-system customers increased during the six months ended June 30, 2008 as compared to the six months ended June 30, 2007 primarily due to continued sales growth and favorable weather in the first quarter of 2008 as compared to 2007. Revenues for our on-system customers increased approximately $6.4 million, or 3.5%. Sales growth contributed an estimated $2.2 million during the six months ended June 30, 2008 while rate changes contributed an estimated $1.9 million. Weather and other related factors increased revenues by an estimated $2.3 million compared to the six months ended June 30, 2007.

The increase in residential and commercial kWh sales and revenues during the six months ended June 30, 2008 was primarily due to the colder weather conditions in the first quarter as compared with 2007 and continued sales growth.

Industrial kWh sales and revenues decreased during the six months ended June 30, 2008 as compared to the same period in 2007 mainly due to overall economic conditions.

On-system wholesale kWh sales increased during the six months ended June 30, 2008 reflecting the continued sales growth and weather discussed above. Revenues associated with these FERC-regulated sales increased more, however, as a result of the fuel adjustment clause applicable to such sales.

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 for the applicable periods ended June 30:

	2008		2007
	Six Months		Six Months
(in millions)	Ended		Ended
Revenues	$	16.0	$	8.6
Expenses	11.8		6.1
Net*	$	4.2	$	2.5

*Differences could occur due to rounding.

Revenues increased during the six months ended June 30, 2008 as compared to the six months ended June 30, 2007 primarily due to sales facilitated by the SPP EIS market that began on

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February 1, 2007. Sales from this market contributed $7.4 million to our off-system electric revenues in the six months ended June 30, 2008 with $5.0 million of related expense as compared to $3.3 million of electric revenues in the second quarter of 2007 with $2.2 million of related expense. Total purchase power related expenses are included in our discussion of purchased power costs below.

Operating Revenue Deductions

During the six months ended June 30, 2008, total electric segment operating expenses increased approximately $14.7 million (8.5%) compared with the same period last year. Purchased power costs increased approximately $8.8 million (22.0%) during the six months ended June 30, 2008 while total fuel costs increased approximately $7.8 million (16.4%). This combined increase of $16.6 million (19.0%) included the effect of increased costs for off-system sales of $5.7 million, and the effect of replacement power for the Asbury and Riverton 8 outages. The increase in purchased power costs primarily reflected higher prices for the power purchased (an estimated $6.4 million) as well as increased purchases on the spot market for replacement energy (an estimated $2.4 million) mainly due to the extended Asbury outage in the first quarter of 2008. The increase in fuel costs was primarily due to increased generation by our gas fired units in the first six months of 2008 (an estimated $6.3 million) mainly due to the extended outage at the Asbury plant that lasted into the first quarter of 2008, as well as an increase in off-system sales and an estimated $4.1 million increase resulting from higher costs for the natural gas we burned in our gas-fired units. These increased costs were partially offset as a result of the unwinding of future physical natural gas positions in February 2008 that reduced fuel expense by approximately $2.1 million in the first quarter of 2008. Increased coal costs contributed an estimated $0.5 million to total fuel costs in the six months ended June 30, 2008. Decreased coal generation, mainly due to the Asbury outage in the first quarter of 2008, decreased fuel costs an estimated $0.1 million while other fuel costs decreased approximately $0.9 million. After assessing the actual cost of the incremental purchased power and gas-fired generation, we estimate the extended outage increased expenses an additional $5.8 million in the first quarter of 2008 (January 1-February 10, 2008).

Regulated operating expenses for our electric segment increased approximately $0.4 million (1.3%) during the six months ended June 30, 2008 as compared to the same period in 2007 primarily due to increases of $1.0 million in transmission and distribution expense, $0.2 million in other steam power expense, $0.2 million in general labor costs and $0.1 million in other power expense. These increases were partially offset by decreases of $0.6 million in uncollectible accounts expense, $0.3 million in employee pension expense, $0.2 million in employee health care expense, and $0.1 million in injuries and damages expense.

Maintenance and repairs expense decreased approximately $4.3 million (26.3%) during the six months ended June 30, 2008 primarily due to a $4.6 million decrease in distribution maintenance costs, as compared to the six months ended June 30, 2007 when there were $4.6 million of incremental costs (and $1.2 million non-incremental tree trimming and labor costs in the first quarter of 2007) related to the January 2007 ice storm. This decrease was partially offset by a $0.8 million increase in maintenance expenses related to tornadoes and other storms in the six months ended June 30, 2008. Also contributing to the decrease during the six months ended June 30, 2008 was a $0.7 million decrease in maintenance and repairs expense at the Iatan plant as compared to the same period in 2007 when there was a planned maintenance and turbine inspection in the first quarter at the Iatan plant and a $0.3 million decrease in maintenance and repairs expense at the Asbury plant. These decreases were partially offset by a $0.7 million increase in maintenance and repairs expense at the SLCC plant due to the extended spring maintenance outage in the second quarter of 2008 and a $0.2 million increase in maintenance and repairs expense at the Riverton plant due to the extended outage on Unit 8 to repair damage to high pressure blades discovered during Riverton’s five–year maintenance outage in May 2008.

Depreciation and amortization expense increased approximately $1.5 million (6.2%) during the six months ended June 30, 2008 mainly due to increased plant in service. Other taxes increased approximately $0.5 million during the six months ended June 30, 2008 due to increased property taxes reflecting our additions to plant in service and increased municipal franchise taxes.

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Twelve Months Ended June 30, 2008 Compared to Twelve Months Ended June 30, 2007

On-System Operating Revenues and Kilowatt-Hour Sales

For the twelve months ended June 30, 2008, kWh sales to our on-system customers increased 0.6% with the associated revenues increasing approximately $19.4 million (5.0%). Rate changes, primarily the January 2007 Missouri rate increase, contributed an estimated $24.2 million to revenues while continued sales growth contributed an estimated $4.7 million. Our electric customer growth for the twelve months ended June 30, 2008 was 0.7%. Weather and other related factors contributed an estimated $1.2 million. These increases were partially offset by a $5.9 million revision to our estimate of unbilled revenues in the third quarter of 2006 and $4.7 million of Interim Energy Charge (IEC) collected in 2006, neither of which reoccurred in 2007. Residential and commercial kWh sales and associated revenues increased primarily due to continued sales growth while the associated revenues also increased due to the Missouri rate increase. Industrial kWh sales decreased for the twelve months ended June 30, 2008, due in part to the continued slowdown in the building construction products industry as well as the revision to our estimate of unbilled revenues and corresponding KWhs in the third quarter of 2006 that did not reoccur in 2007. Industrial revenues increased, reflecting the aforementioned rate increase. On-system wholesale kWh sales increased reflecting the continued sales growth discussed above. 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.

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 for the applicable periods ended June 30:

	2008		2007
	Twelve Months		Twelve Months
(in millions)	Ended		Ended
Revenues	$	29.9	$	16.1
Expenses	21.6		11.6
Net*	$	8.3	$	4.5

*Differences could occur due to rounding.

Revenues less expenses increased during the twelve months ended June 30, 2008 as compared to the same period in 2007 primarily due to sales facilitated by the SPP EIS market that began on February 1, 2007. Sales from this market contributed $12.9 million to our off-system electric revenues for the twelve months ended June 30, 2008 with $9.0 million of related expense as compared to $3.3 million of electric revenues for the twelve months ended June 30, 2007 with $2.2 million of related expense. In addition, in May 2007, we entered into a contract with Kansas City Board of Public Utilities (BPU) for the sale of energy and capacity for June through September of 2007 and 2008. Capacity revenue will total approximately $1.3 million each year with the energy portion dependent upon the number of hours the contract is utilized by BPU. Twelve months ended June 30, 2008 revenues from the BPU contract were approximately $2.1 million as compared to $0.3 million for the twelve months ended June 30, 2007. Total purchase power related expenses are included in our discussion of purchased power costs below.

Operating Revenue Deductions

During the twelve months ended June 30, 2008, total electric segment operating expenses increased approximately $40.2 million (11.8%) compared to the year ago period. Total fuel costs increased approximately $23.6 million (24.2%) during the twelve months ended June 30, 2008 and purchased power costs increased $14.3 million (19.9%) during the same period. This combined increase of $37.9 million (22.3%) included the effect of increased costs for off-system sales of $10.0

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million and the effect of replacement power for the Asbury and Riverton 8 outages. The increase in fuel costs was mainly due to increased generation by our gas fired units (an estimated $30.3 million) primarily in the first quarter of 2008 and fourth quarter of 2007 due to the extended outage at the Asbury plant and to the increase in off-system sales. Also adding to the increase were higher costs for the natural gas we burned in our gas-fired units (an estimated $1.6 million). These increased costs were partially offset as a result of the unwinding of future physical natural gas positions in February 2008 that reduced fuel expense by approximately $2.1 million in the first quarter of 2008. Decreased coal generation, mainly due to the Asbury outage, decreased fuel costs an estimated $5.9 million, partially offset by increased coal costs (approximately $0.7 million) during the twelve months ended June 30, 2008. Other fuel costs decreased approximately $1.0 million. The increase in purchased power costs primarily reflected higher prices for the power purchased (an estimated $9.8 million) as well as increased purchases on the spot market for replacement energy (an estimated $4.5 million) mainly in the first quarter of 2008 and fourth quarter of 2007 due to the extended Asbury outage as well as the extended SLCC outage in the second quarter of 2008. After assessing the actual cost of the incremental purchased power and gas-fired generation, we estimate the extended outage at Asbury increased expenses an additional $5.8 million in the first quarter of 2008 (January 1-February 10, 2008) and $3.5 million in the fourth quarter of 2007 (December 8-December 31, 2007).

Regulated operating expenses increased approximately $3.8 million (6.6%) during the twelve months ended June 30, 2008 as compared to the same period last year due primarily to increases of $1.7 million in transmission and distribution expense, $0.7 million in customer accounts expense, $0.6 million in employee pension expense, $0.4 million in general labor costs, $0.3 million in other steam power expense, $0.2 million in other power expense and $0.2 million in regulatory commission expense. These increases were partially offset by a decrease of $0.3 million in employee health care costs.

Maintenance and repairs expense decreased approximately $1.7 million (6.0%) during the twelve months ended June 30, 2008, primarily due to a $2.7 million decrease in distribution maintenance costs (primarily overhead line maintenance expense partially offset by increased tree trimming efforts) as compared to the year ago period when there was a January 2007 major ice storm. Also contributing to the decrease during the twelve months ended June 30, 2008 was a $0.8 million decrease in maintenance and repairs expense at the Iatan plant as compared to the same period in 2007 when there was a planned maintenance and turbine inspection at the Iatan plant in the first quarter of 2007 and a $0.4 million decrease in maintenance and repairs expense at the State Line plant. These decreases were partially offset by increases of $0.8 million in transmission maintenance expense, $0.5 million in maintenance and repairs expense at the Asbury plant, $0.4 million in maintenance and repairs expense at the Energy Center, $0.3 million in maintenance and repairs expense at the Riverton plant related to the five-year maintenance outage and $0.2 million in maintenance and repairs expense at the SLCC plant related to the extended 2008 spring maintenance outage.

Depreciation and amortization expense increased approximately $8.4 million (19.6%) mainly due to $5.1 million regulatory amortization related to the December 21, 2007 Missouri rate order that has been recorded as depreciation expense as well as increased plant in service. Other taxes increased approximately $1.1 million due to increased property taxes reflecting our additions to plant in service and increased municipal franchise taxes.

Total electric segment operating expenses were also reduced by approximately $2.0 million for the 12 months ended June 30, 2008 as compared to the same period in 2007 due to a $1.2 million gain we recognized in the fourth quarter of 2007 from the sale of our steel unit train set and a $0.8 million loss in the fourth quarter of 2006 related to a plant disallowance required by rate order.

Gas Segment

Gas Segment Operating Revenues and Sales

During the second quarter of 2008, our total natural gas revenues were approximately $9.1 million as compared to $8.4 million in the second quarter of 2007. An increase in sales in the

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second quarter of 2008 as compared to the second quarter of 2007 resulted in higher revenues despite an 8.28% overall decrease in our Purchased Gas Adjustment (PGA) Clause during the second quarter of 2008 as compared to the same period in 2007.

For the six months ended June 30, 2008, our total natural gas revenues were approximately $36.4 million as compared to $36.0 million for the six months ended June 30, 2007. The winter months are high sales months for the natural gas business, whose heating season runs from November to March of each year.

For the twelve months ended June 30, 2008, our total natural gas revenues were approximately $60.3 million as compared to $59.5 million for the twelve months ended June 30, 2007.

The following tables detail our natural gas sales and revenues for the periods ended June 30:

	Total gas delivered to customers
	bcf Sales				bcf Sales				bcf Sales
	Second	Second			6 Months	6 Months			12 Months	12 Months
	Quarter	Quarter	%		Ended	Ended	%		Ended	Ended	%
	2008	2007	Change*		2008	2007	Change*		2008	2007	Change*
Residential	0.32	0.36	(9.1	)%	1.85	1.72	7.5	%	2.96	2.77	6.9	%
Commercial	0.17	0.18	(8.4	)	0.84	0.76	10.1		1.38	1.28	7.7
Industrial**	0.15	0.01	1,433.4		0.20	0.03	625.2		0.25	0.06	331.2
Public Authorities	0.00	0.00	(14.0	)	0.02	0.02	15.2		0.03	0.03	8.2
Total retail sales*	0.64	0.55	16.9		2.92	2.53	15.1		4.63	4.14	11.7
Transportation sales**	0.84	0.92	(8.7	)	2.20	2.27	(3.1	)	4.23	4.22	0.3
Total gas operating sales*	1.49	1.47	0.9		5.12	4.80	6.5		8.86	8.36	5.9

	Operating Revenues ($ in millions)
	Second		Second				6 Months		6 Months				12 Months		12 Months
	Quarter		Quarter		%		Ended		Ended		%		Ended		Ended		%
	2008		2007		Change*		2008		2007		Change*		2008		2007		Change*
Residential	$	5.0	$	5.4	(6.8	)%	$	23.1	$	24.0	(3.7	)%	$	38.3	$	39.0	(1.8	)%
Commercial	2.2		2.4		(9.0	)	9.6		9.9		(2.6	)	16.3		16.5		(1.1	)
Industrial**	1.4		0.1		1,236.4		1.8		0.3		509.2		2.2		0.6		257.1
Public Authorities	0.0		0.0		(10.2	)	0.3		0.2		2.3		0.4		0.4		(3.2	)
Total retail sales***	$	8.6	$	7.9	8.5		$	34.8	$	34.4	1.1		$	57.3	$	56.5	1.3
Transportation sales**	0.5		0.5		5.8		1.5		1.5		1.4		2.8		2.8		(0.0	)
Total gas operating sales***	$	9.1	$	8.4	8.4		$	36.3	$	35.9	1.1		$	60.1	$	59.3	1.2

*Differences could occur due to rounding.

**Percentage change reflects the transfer of a customer from transportation sales to industrial.

***Revenues exclude forfeited discounts, reconnect fees, miscellaneous service revenues, etc.

Gas Segment Operating Revenue Deductions

During the second quarter of 2008, EDG’s cost of natural gas sold and transported was approximately $5.3 million as compared to $4.7 million during the second quarter of 2007. An overall increase in volume was offset by lower rates. Our PGA clause had an 8.28% overall decrease in the second quarter of 2008 as compared to the second quarter of 2007. However, in June 2008 we increased our PGA clause by 38% as compared to the previous PGA that had been in effect since November 2007.

For the six months ended June 30, 2008, EDG’s cost of natural gas sold and transported was approximately $23.0 million as compared to $23.4 million for the same period in 2007.

For the twelve months ended June 30, 2008, EDG’s cost of natural gas sold and transported was approximately $37.2 million as compared to $38.0 million for the same period in 2007.

Our PGA clause allows us to recover from our customers, subject to routine regulatory review, the cost of purchased gas supplies, transportation and storage, including costs, cost

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reductions, and related carrying costs associated with the use of financial instruments to hedge the purchase price of natural gas.

Total other operating expenses were $2.6 million for both the second quarter of 2008 and the second quarter of 2007. EDG had a net loss of $0.6 million for the second quarter of 2008 as compared to a $0.7 million net loss for the second quarter of 2007.

For the six months ended June 30, 2008, total other operating expenses were $5.1 million as compared to $5.5 million for the same period in 2007. EDG had net income of $1.8 million for the six months ended June 30, 2008 as compared to $0.9 million 2007.

For the twelve months ended June 30, 2008, total other operating expenses were $9.9 million as compared to $10.5 million for the same period in 2007. EDG had net income of $1.8 million for the twelve months ended June 30, 2008 as compared to $0.3 million in 2007. Approximately $1.2 million in transition costs were paid to Aquila, Inc. in 2006 for billing and other transition services. These non-recurring costs ended when all services were transitioned by November 1, 2006.

Other Segment

Our other segment includes leasing of fiber optics cable and equipment (which we are also using in our own utility operations). The following table represents our results of continuing operations for our other segment for the applicable periods ended June 30:

	Three Months Ended				Six Months Ended				Twelve Months Ended
(in millions)	2008		2007		2008		2007		2008		2007
Revenues	$	1.3	$	0.9	$	2.4	$	1.7	$	4.3	$	3.3
Expenses	1.0		0.9		1.9		1.7		3.5		3.4
Net income (loss) from continuing operations*	$	0.3	$	0.0	$	0.5	$	0.0	$	0.9	$	(0.1	)

*Differences could occur due to rounding.

Consolidated Company

Income Taxes

Our consolidated provision for income taxes decreased approximately $0.8 million during the second quarter of 2008 as compared to the same period in 2007, primarily resulting from lower income. Our consolidated effective federal and state income tax rate for the second quarter of 2008 was 31.9% as compared to 32.1% for the second quarter of 2007.

Our consolidated provision for income taxes increased approximately $0.7 million during the six months ended June 30, 2008 as compared to the same period in 2007. This resulted primarily from increased income. Our consolidated effective federal and state income tax rate for the six months ended June 30, 2008 was 31.2% as compared to 29.8% for the same period in 2007. The effective tax rate for the six months ended June 30, 2008 varied in part as we recognized less tax-related Medicare Part D benefits in the first quarter of 2008 as compared to the same period in 2007.

Our consolidated provision for income taxes decreased approximately $6.1 million during the twelve months ended June 30, 2008 as compared to the twelve months ended June 30, 2007, primarily resulting from lower income. Our effective federal and state income tax rate for the twelve months ended June 30, 2008 was 30.8% as compared to 34.2% for the same period in 2007. The effective tax rate for the 2008 twelve month period decreased as we recognized increased benefits from the equity component of AFUDC and expenses related to plant removal costs.

Nonoperating Items

Total allowance for funds used during construction (AFUDC) increased $1.4 million in the second quarter of 2008 as compared to 2007. AFUDC increased $1.8 million during the six months ended June 30, 2008 and increased $2.6 million during the twelve months ended June 30, 2008 as compared to the same periods in the prior year due to higher levels of construction in each period.

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AFUDC is comprised of the cost of borrowed funds and the cost of equity funds applicable to our construction program and are capitalized as a cost of construction. This accounting practice offsets the effect on earnings of the cost of financing current construction, and treats such financing costs in the same manner as construction charges for labor and materials.

Total interest charges on long-term debt increased $0.8 million (9.7%) in the second quarter of 2008, $1.9 million (12.7%) for the six months ended June 30, 2008 and $4.3 million (14.8%) for the twelve months ended June 30, 2008 as compared to the prior year periods (offset by the increased AFUDC discussed above). The increases in all three periods reflect the interest on the $90 million principal amount of first mortgage bonds we issued May 16, 2008, the proceeds of which were added to our general funds and used primarily to pay down short-term indebtedness incurred, in part, as a result of our on-going construction program. The increases in both the six months ended and twelve months ended June 30, 2008 periods also reflect the interest on the $80 million principal amount of first mortgage bonds we issued March 26, 2007, the proceeds of which were added to our general funds and used to pay down short-term indebtedness incurred, in part, as a result of our on-going construction program.

Short-term debt interest was virtually the same in the second quarter of 2008 as it was in the second quarter of 2007, while decreasing $0.5 million for the six months ended June 30, 2008, reflecting decreased usage of short-term debt in that period. Short-term debt interest increased $0.1 million for the twelve months ended June 30, 2008 as compared to the same period in 2007.

Earnings from discontinued operations were approximately $0.1 million in the twelve month period ended June 30, 2008 and approximately $0.1 million in the twelve month period ended June 30, 2007, which included operations and gains recognized from the sales of MAPP, Conversant and Fast Freedom.

Other Comprehensive Income

The change in the fair value of the effective portion of our open gas contracts designated as cash flow hedges for our electric business 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 other 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. No interest rate derivative contracts were open or settled during the periods shown below.

The following table sets forth the pre-tax gains/(losses) of our natural gas contracts for our electric segment that have settled and been reclassified, the pre-tax change in the fair market value (FMV) of our open contracts and the tax effect in Other Comprehensive Income for the presented periods ended June 30:

	Change in Other Comprehensive Income
	Three Months Ended						Six Months Ended						Twelve Months Ended
(in millions)	2008			2007			2008			2007			2008			2007
Natural gas contracts settled (1)	$	(1.7	)	$	(0.2	)	$	(2.6	)	$	—		$	(4.1	)	$	(0.6	)
Change in FMV of open contracts for natural gas	$	22.8		$	5.7		$	33.8		$	8.6		$	30.4		$	3.4
Taxes	$	(8.0	)	$	(2.1	)	$	(11.9	)	$	(3.3	)	$	(10.0	)	$	(1.1	)
Total change in OCI – net of tax	$	13.1		$	3.4		$	19.3		$	5.3		$	16.3		$	1.7

(1) Reflected in fuel expense

Our average cost for our open financial natural gas hedges increased from $5.527/Dth at March 31, 2008 to $5.864/Dth at June 30, 2008.

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RATE MATTERS

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

Electric Segment

The following table sets forth information regarding electric and water rate increases since January 1, 2006:

		Annual		Percent
	Date	Increase		Increase		Date
Jurisdiction	Requested	Granted		Granted		Effective
Missouri - Electric	February 1, 2006	$	29,369,397	9.96	%	January 1, 2007
Missouri - Electric	October 1, 2007	$	22,040,395	6.70	%	Pending*

*We anticipate the rates will become effective by September 1, 2008.

Missouri

2006 Rate Case

On February 1, 2006, we filed a request with the MPSC for an annual increase in base rates for our Missouri electric customers in the amount of $29.5 million, or 9.63%. We also requested transition from the IEC from an earlier case to Missouri’s new fuel adjustment mechanism. The MPSC issued an order May 2, 2006, however, ruling that we may have the option of requesting that the IEC be terminated, but we may not request the implementation of an energy cost recovery mechanism while the current IEC is effective. The MPSC issued an order on December 21, 2006 granting us an annual increase of $29.4 million, or 9.96%, with an effective date of January 1, 2007 and eliminating the IEC. Pursuant to this order, the collected IEC was not refunded. The increase included an authorized return on equity of 10.9% and included our fuel and energy costs as a component of base electric rates. This order also allowed deferral of any other postretirement benefits that are different from those allowed recovery in this rate case. This treatment is similar to treatment afforded pension costs in our March 2005 rate case. This order also approved regulatory treatment of additional liabilities arising from the adoption of FAS 158. We also agreed to write off $1 million of the cost of our Energy Center 2 construction project. The Missouri jurisdictional portion of this agreement resulted in a pre tax write off of $0.8 million in the fourth quarter of 2006.

The $29.4 million authorized increase in annual revenues includes $19.4 million resulting from an increase in base rates and $10.4 million resulting from “regulatory amortization.” The regulatory amortization, which is treated as additional book depreciation for rate-making purposes and is so reflected in the financial statements, was granted to provide additional cash flow to enhance the financial support for our current generation expansion plan. This regulatory amortization is related to our investment in Iatan 2 and also includes our Riverton V84-3A2 combustion turbine (Unit 12) and the environmental improvements and upgrades at Asbury and Iatan 1, all of which are part of the Experimental Regulatory Plan approved by the MPSC subject to subsequent prudency review of actual expenditures. Amounts granted as regulatory amortization will reduce our rate base used in determining our base rates in subsequent rate cases.

On March 19, 2007, the OPC filed a Petition for Writ of Mandamus with the Missouri Supreme Court seeking an order requiring the MPSC to vacate and rescind its December 29, 2006 order approving tariffs and directing the MPSC to provide an effective date for any subsequent tariff approval order that allows at least ten days to prepare and file an application for rehearing. On October 30, 2007, the Supreme Court issued an opinion directing the MPSC to vacate its December 29 order approving tariffs and allow the OPC a reasonable time to prepare and file an application for rehearing. The Court did not examine the lawfulness or reasonableness of the substance of the MPSC’s December 29, 2006 order approving tariffs, and considered only the timing of the issuance

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of the order. The Court also did not consider the underlying tariffed rates which continue in force and in effect.

Acting upon the opinion of the Missouri Supreme Court, the MPSC issued an order on December 4, 2007, effective December 14, 2007, vacating the December 29, 2006 order and re-approving the tariffs and the same resulting increase in rates. The OPC and intervenors Praxair, Inc. and Explorer Pipeline Company, filed applications for rehearing with the MPSC regarding this order, raising various issues referred to below. These applications for rehearing remain pending before the MPSC.

On March 26, 2008, the MPSC issued its Order Granting Reconsideration of Report and Order, to be effective April 5, 2008, and its Report and Order Upon Reconsideration, to be effective April 5, 2008, in which the MPSC made additional findings and reaffirmed the rate increase originally authorized in December of 2006. In this order, the MPSC made two adjustments. An increase in the return on rate base was offset by a decrease in the regulatory amortization from $10.4 million to $10.2 million. The OPC and intervenors Praxair and Explorer Pipeline filed applications for rehearing regarding this Report and Order Upon Reconsideration, raising objections to many of the issues addressed in the order, including but not limited to issues relating to return on equity, fuel and purchased power expense and, in the case of the intervenors, the propriety of regulatory amortization under Missouri public utility law. These applications for rehearing remain pending before the MPSC.

On March 18, 2008, the OPC filed a Petition for Writ of Mandamus with the Missouri Supreme Court, purportedly to force the MPSC to comply with the Missouri Supreme Court’s opinion and order of October 30, 2007. The OPC, the MPSC, the intervenors and Empire filed written briefs. OPC and the intervenors claim, among other things, that the MPSC did not comply with the Court’s order to vacate its rate order of December 29, 2006. We and the MPSC believe that the MPSC fully complied with the Court’s order. Oral arguments were made before the Missouri Supreme Court on May 13, 2008.

2007 Rate Case

On October 1, 2007, we filed a request with the MPSC for an annual increase in base rates for our Missouri electric customers in the amount of $34.7 million, or 10.11%. We requested recovery of our investment in the new 150-megawatt combustion turbine, Unit 12, at our Riverton plant, capital expenditures associated with the construction of a selective catalytic reduction system at our Asbury Plant, capital expenditures and expenses related to the January and December 2007 ice storms and other changes in our underlying costs. We also requested implementation of a fuel adjustment clause in Missouri which would permit the distribution to Missouri customers of changes in fuel and purchased power costs.

The MPSC issued an order on July 30, 2008, effective August 9, 2008, granting an annual increase in base rates for Missouri electric customers in the amount of $22.0 million, or 6.7%, based on a 10.8% return on equity. We anticipate that the new rates will go into effect by September 1, 2008. The order contains two components. The first component provides an addition to base rates of approximately $27.7 million. This increase in base rates was partially offset by a $5.7 million downward adjustment to regulatory amortization, which is the second component. Regulatory amortization provides us additional cash through rates during the current construction cycle. This construction, which is part of our long-range plan to ensure reliability, includes the facilities at the Riverton Power Plant and Iatan 2 Power Plant, as well as environmental improvements at the Asbury Power Plant and at Iatan 1. The regulatory amortization is now approximately $4.5 million. The MPSC also authorized a fuel adjustment clause for our Missouri customers. The MPSC established a base rate for the recovery of fuel and purchased power expenses used to supply energy and the clause permits the distribution to customers of 95% of the changes in fuel and purchased power costs above or below the base. Rates related to the fuel adjustment clause will be modified twice a year subject to the review and approval by the MPSC. The MPSC also approved the Stipulations and Agreements providing for the recovery of deferred expenses for the 2007 ice storms and continuation of the pension and other post-retirement employee benefits trackers established in our 2006 Missouri rate case. The MPSC order also established a two-way tracker, which allows us to

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defer the amount over and under the cost of compliance to a regulatory asset or liability, for the cost of compliance with the vegetation and infrastructure reliability rules adopted by the MPSC which had an effective date of July 2008.

Kansas

In accordance with our last Kansas rate case, we were to seek approval of an explicit hedging program in a separate docket filed with the Kansas Corporation Commission (KCC) by March 1, 2006. We requested and received an extension until April 1, 2006 and made this filing on March 30, 2006. On February 4, 2008, the KCC issued an order denying the request for the approval of our existing natural gas hedging program. All gains or losses related to the financial instruments used to fix the future price of natural gas will be excluded from the Energy Cost Adjustment clause implemented in the last Kansas rate case and future base electric rates in Kansas.

Ice Storm Recovery

We filed applications for Accounting Authority Orders in Oklahoma and Kansas and filed a request for storm recovery in Arkansas respecting costs incurred due to the two major ice storms in 2007. On May 23, 2008, the Arkansas Public Service Commission issued an Order allowing us to defer approximately $0.4 million of extraordinary incremental expenses incurred as a result of the 2007 ice storms as a regulatory asset and amortize such costs over a 5 year period beginning with the first full month following the storms. On June 24, 2008, the State Corporation Commission of the State of Kansas issued an Order approving our application for an accounting order to accumulate and defer for recovery in future rate case proceedings, approximately $1.1 million of 2007 ice storm costs as a regulatory asset to be amortized over a 10 year period. On June 25, 2008, the Corporation Commission of Oklahoma issued a Final Order approving a Joint Stipulation and Settlement Agreement giving us permission to defer and record approximately $0.5 million of 2007 ice storm costs as a regulatory asset and authorizing recovery of the regulatory asset over a five year period, via a rider effective July 1, 2008. We were granted rate recovery of the Missouri ice storm costs as part of the order issued by the MPSC on July 30, 2008 as discussed above.

Gas Segment

On June 1, 2006, The Empire District Gas Company acquired the Missouri natural gas distribution operations of Aquila, Inc. (Missouri Gas). The Missouri Gas properties consist of 44 Missouri communities in northwest, north central and west central Missouri. The rates, excluding the cost of gas, are the same as had been in effect at Aquila, Inc. We agreed in the unanimous stipulation and agreement filed with the MPSC on March 1, 2006 and approved on April 18, 2006, to not file a rate increase request for non-gas costs for a period of 36 months following the closing date of the acquisition. We have also agreed to use Aquila Inc.’s current depreciation rates and were allowed to adopt the pension cost recovery methodology approved in our electric Missouri Rate Case effective March 27, 2005.

A PGA clause is included in our gas rates which allows for the over recovery or under recovery of actual gas costs compared to the cost of gas in the PGA rate. This PGA clause allows us to make rate changes periodically (up to four times) throughout the year in response to weather conditions, natural gas prices and supply demands, rather than in one possibly extreme change per year. The Actual Cost Adjustment (ACA) is a scheduled yearly filing with the MPSC filed between October 15 and November 4 each year. This filing establishes the amount to be recovered from customers for the over/under recovered yearly amounts. A PGA is included in the ACA filing. An optional PGA filing without the ACA can be filed up to three times each year, provided a filing does not occur within 60 days of a previous filing. Our last ACA filing was completed on October 24, 2007. Our last PGA filing was effective June 6, 2008.

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COMPETITION

Electric Segment

SPP-RTO

On February 1, 2007, the SPP regional transmission organization (RTO) launched its energy imbalance services market (EIS). With the implementation of the SPP RTO EIS market and transmission expansion plans of the SPP RTO, we anticipate that our continued participation in the SPP will provide long-term benefits to our customers and other stakeholders. Our experience to date in the EIS market indicates that we have received benefits through our participation.

In general, the SPP RTO EIS market is providing real time energy for most participating members within the SPP regional footprint. Imbalance energy prices are based on market bids and status/availability of dispatchable generation and transmission within the SPP market footprint. In addition to energy imbalance service, the SPP RTO performs a real time security-constrained economic dispatch of all generation voluntarily offered into the EIS market to the market participants to also serve the native load.

We will continue to actively engage with the SPP RTO, other members of the SPP and staffs of our state commissions to evaluate the impact and value of EIS market participation.

On February 16, 2007, the FERC issued a Final Order No. 890, which instituted numerous reforms to its Order 888 open access transmission pro forma tariff (OATT) which was issued in April 1996. The purpose of the Order was (i) to strengthen the OATT to ensure that it better achieves its original purpose of remedying undue discrimination for the provision of transmission service, (ii) to provide greater specificity in the OATT to reduce opportunities for the exercise of undue discrimination, make undue discrimination easier to detect, and facilitate the FERC’s enforcement, and (iii) to increase transparency in the rules applicable to planning and use of the transmission system. The FERC’s actions required modifications to the SPP and our OATTs as well as regional and local transmission planning processes. We and SPP submitted our respective Order 890 compliance filings of our OATTs on October 11, 2007. Compliance modifications to our OATT filing were not material and we anticipate them being accepted. The SPP proposed modifications to its regional and local area transmission planning processes, pursuant to Order 890, in its December 7, 2007 FERC filing. An issuance from the FERC on our and SPP’s filings is pending. In December 2007, the FERC issued Order 890A, reconfirming its February Order 890.

FERC Market Power Order

In April and July 2004, the FERC issued orders regarding new testing standards for assessing market power by entities that have wholesale market-based rate tariffs filed with the FERC. The parameters included in the tests are such that most investor owned electric utilities fail the test within their own control area and are subject to a rebuttable presumption of market power. Entities with wholesale market based rates tariffs are subject to a triennial filing to test for market power and are required to apply the new testing criteria. FERC determination of market power would result in the inability for a utility to continue to charge such market-based rates. In September 2004, we submitted amended and updated market power analyses filings.

On March 3, 2005, the FERC issued an order commencing an investigation to determine if we had market power within our control area based on our failure to meet one of the FERC’s wholesale market share screens. We filed responses to that order in May and June 2005 and in early January 2006. On August 15, 2006, the FERC issued its order accepting Empire’s proposed mitigation to become effective May 16, 2005, subject to a further compliance filing as directed in the order. Relying on a series of orders issued since March 17, 2006 in other proceedings, the FERC rejected our tariff language and directed us to file revisions to our market-based tariff to provide that service under the tariff applies only to sales outside our control area. The FERC directed us to make refunds, with interest, by September 15, 2006, which we initially estimated to be approximately $0.6 million (excluding interest) covering over a thousand hourly energy sales since May 16, 2005 to numerous counterparties external to our system for wholesale sales made at market prices above

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the cost based prices permitted under the mitigation proposal accepted by the FERC. The refund obligation applied to certain wholesale power sales made “inside” our service area at market based rates, even though consumption of the energy occurred outside our service area. In response to the order, we filed a Motion For Extension of time and expedited treatment regarding the refund and requested that such refund be delayed until 15 days after the FERC’s order on our rehearing request. On September 5, 2006, the FERC granted the Motion For Extension, as requested.

On September 14, 2006, we filed a Request For Rehearing of the FERC’s August 15, 2006 order regarding the refund and market power mitigation we had proposed. We requested a rehearing and a waiver of the refund requirement in its entirety. On April 25, 2008, the FERC issued an Order that rejected our Request For Rehearing, required a Compliance Filing of our market based rate tariff and ordered refunds with interest. We made our Compliance Filing and issued refunds totaling $340,608, including interest, on May 27, 2008. We were also required to file an informational refund report with the FERC on June 26, 2008.

As a result of the FERC’s requirement for us to issue the aforementioned refunds and our belief that the FERC erred in its orders, on June 30, 2008 we initiated a Petition For Review of the FERC’s orders on our market based rate refunds in the United States Court of Appeals – District of Columbia Circuit (DC Circuit). We have requested a consolidation of our Petition with the similar petitions of Westar Energy and Mid American Energy Company. A decision on consolidation is pending before the DC Circuit. If a decision is reached in our favor, the DC Circuit will likely remand the FERC’s orders back to the FERC for reconsideration. It is expected that the judicial review of the Petitions will take several months.

Other FERC Rulemaking

On June 21, 2007, the FERC issued an Advance Notice of Proposed Rulemaking (ANOPR) on potential reforms to improve operations in organized wholesale power markets, such as the SPP RTO in which we participate. The FERC is seeking comment in the following areas: (i) the role of demand response in the organized markets, (ii) increasing opportunities for long-term power contracts, (iii) strengthening market monitoring and (iv) the responsiveness of RTOs and ISOs to customers and stakeholders.

On January 28, 2008, we made a filing at the FERC related to certain non-rate and ministerial revisions to our currently effective wholesale Open Access Transmission Tariff (OATT), which included the elimination of certain tariff sections that have become moot in light of our membership in the SPP, as well as correction of the formatting of our OATT for consistency with Order No. 614.

On April 2, 2008, FERC accepted our revised OATT, as filed, with an effective date of January 29, 2008.

Gas Segment

Non-residential gas customers whose annual usage exceeds certain amounts may purchase natural gas from a source other than EDG. EDG does not have a non-regulated energy marketing service that sells natural gas in competition with outside sources. EDG continues to receive non-gas related revenues for distribution and other services if natural gas is purchased from another source by our eligible customers.

LIQUIDITY AND CAPITAL RESOURCES

We used approximately $114.1 million of cash for regulated capital expenditures during the six months ended June 30, 2008. Our primary sources of cash flow for these expenditures during the six months ended June 30, 2008 were $66.1 million in internally generated funds from continuing operations and $90.0 million in gross proceeds from first mortgage bonds.

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Cash Provided by Operating Activities

Our net cash flows provided by continuing operating activities were $66.1 million during the six months ended June 30, 2008 as compared to $38.1 million for the six months ended June 30, 2007. Net income increased $1.5 million. Changes in balance sheet items, primarily accounts receivable, accounts payable and accrued liabilities positively impacted cash flow this year compared to last year.

Capital Requirements and Investing Activities

Our capital expenditures totaled approximately $53.6 million during the second quarter of 2008 compared to approximately $41.7 million for the same period in 2007. Our capital expenditures totaled approximately $115.0 million during the six months ended June 30, 2008 compared to approximately $85.5 million for the same period in 2007. These capital expenditures include AFUDC, capital expenditures to retire assets and benefits from salvage.

Our net cash flows used in investing activities increased $31.3 million during the six months ended June 30, 2008 as compared to the same period in 2007, primarily reflecting construction expenditures for Plum Point Unit 1 and Iatan 2, as well as the payments for the capitalized portion of the December 2007 ice storm which were accrued but not paid as of December 31, 2007.

A breakdown of the capital expenditures for the quarter and six months ended June 30, 2008 is as follows:

	Capital Expenditures
	Quarter Ended			Six Months Ended
(in millions)	June 30, 2008			June 30, 2008
Distribution and transmission system additions	$	10.2		$	22.8
New Generation – Plum Point Energy Station	9.4			18.3
New Generation – Iatan 2	21.1			41.2
Storms(1)	2.6			3.8
Additions and replacements – Asbury	0.4			3.9
Additions and replacements – Iatan 1	6.9			14.3
Additions and replacements - State Line Unit 1, SLLC, Riverton, Energy Center, and Ozark Beach	0.3			0.6
Gas segment additions and replacements	0.3			0.7
Transportation	0.1			0.2
Other (including retirements and salvage -net)	0.3			1.6
Subtotal	51.6			107.4
Other capital expenditures (primarily fiber optics)	0.7			1.1
Subtotal capital expenditures incurred (2)	52.3			108.5
Change in capital expenditures accrual (3)	2.8			9.1
Less AFUDC equity capitalized	(1.5		)	(2.6		)
Total cash outlay	$	53.6		$	115.0

(1) For the six months ended June 30, 2008, storm costs of $0.1 million are specifically related to capital expenditures in the first quarter of 2008 associated with the December 2007 ice storm and $2.4 million are specifically related to capital expenditures in the second quarter of 2008 associated with tornadoes in May 2008.

(2) Expenditures incurred represent the total cost for work completed for the projects during the periods ending June 30, 2008. Discussion of capital expenditures throughout this 10-Q is presented on this basis.

(3) Adjustment to reflect actual cash flow related to capital expenditures. These are the net of expenditures unpaid at the end of the reporting period and expenditures paid in the reporting period, but incurred prior to the reporting period.

Approximately 44% of our cash requirements for capital expenditures during the second quarter of 2008 were satisfied internally from operations (funds provided by operating activities less dividends paid). The remaining amounts of such requirements were satisfied from short-term borrowings and proceeds from our sales of common stock and debt securities discussed below

We currently expect that internally generated funds will provide approximately 52% of the funds required for the remainder of our budgeted 2008 capital expenditures. We intend to utilize a combination of short-term debt, the proceeds of sales of long-term debt and/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 additional

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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. For further information see Note 5 of “Notes to Consolidated Financial Statements (Unaudited).”

We had estimated our capital expenditures for our share of Iatan 2 to be approximately $72.4 million, $43.8 million and $33.1 million in 2008, 2009 and 2010, respectively. As a result of KCP&L’s updated forecast, however, we now estimate these expenditures to be approximately $72.0 million, $67.5 million and $36.1 million in 2008, 2009 and 2010, respectively. We had estimated our capital expenditures for our share of the Iatan 1 environmental upgrades to be approximately $26.7 million, $1.4 million and $0.3 million in 2008, 2009 and 2010, respectively, but now estimate these expenditures to be approximately $25.7 million in 2008 and $17.5 million in 2009 with an in-service date of February 2009. We had estimated our capital expenditures for the construction of a combustion turbine previously scheduled to be installed by the summer of 2011 to be approximately $0.2 million, $4.8 million and $17.0 million in 2008, 2009 and 2010, respectively. As a result of our delaying the combustion turbine at least one year, however, we now estimate these expenditures to be approximately $0.2 million, $0.0 million, $4.8 million and $17.0 million in 2008, 2009, 2010 and 2011, respectively.

Financing Activities

Our net cash flows received from financing activities were $47.4 million in 2008 compared to $34.7 million in 2007.

On May 16, 2008, we issued $90 million principal amount of first mortgage bonds. The net proceeds of approximately $89.4 million, less $0.3 million of legal and other financing fees, were added to our general funds and used primarily to pay down short-term indebtedness incurred, in part, as a result of our on-going construction program.

On December 12, 2007, we sold 3,000,000 shares of our common stock in an underwritten public offering for $23.00 per share. The sale resulted in net proceeds of approximately $65.7 million ($69.0 million less issuance costs of $3.3 million). The proceeds were added to our general funds and used to pay down short-term indebtedness incurred, in part, as a result of our on-going construction program.

On March 26, 2007, we issued $80 million principal amount of first mortgage bonds. The net proceeds of approximately $79.1 million, less $0.4 million of legal and other financing fees, were added to our general funds and used to pay down short-term indebtedness incurred, in part, as a result of our on-going construction program.

We have filed a $400 million shelf registration statement with the SEC covering our common stock, unsecured debt securities, preference stock, first mortgage bonds and trust preferred securities. We plan to use a portion of the proceeds from issuances under this shelf, once it becomes effective, to fund a portion of the capital expenditures for our new generation projects.

On July 15, 2005, we entered into a $150 million unsecured revolving credit facility until July 15, 2010. Borrowings (other than through commercial paper) are at the bank’s prime commercial rate or LIBOR plus 100 basis points based on our current credit ratings and the pricing schedule in the line of credit facility. On March 14, 2006, we entered into the First Amended and Restated Unsecured Credit Agreement which amends and restates the $150 million unsecured revolving credit facility. The principal amount of the credit facility was increased to $226 million, with the additional $76 million allocated to support a letter of credit issued in connection with our participation in the Plum Point Energy Station project. This extra $76 million of availability reduces over a four year period in line with the amount of construction expenditures we owe for Plum Point Unit 1 and was $27.5 million as of August 1, 2008. The unallocated credit facility is used for working capital, general corporate purposes and to back-up our use of commercial paper. This facility requires our total indebtedness (which does not include 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 and amortization) to be at least two times our interest charges (which includes interest on the note payable to the securitization trust) for the trailing four

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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. As of June 30, 2008, we are in compliance with these ratios. This credit facility is also subject to cross-default if we default on in excess of $10 million in the aggregate on our other indebtedness. This arrangement does not serve to legally restrict the use of our cash in the normal course of operations. There were no outstanding borrowings under this agreement at June 30, 2008, however, $12.0 million of the availability thereunder was used at such date to back up our outstanding commercial paper.

The principal amount of all series of first mortgage bonds outstanding at any one time under the EDE Mortgage is limited by terms of the mortgage to $1 billion. Substantially all of the property, plant and equipment of The Empire District Electric Company (but not its subsidiaries) is subject to the lien of the EDE Mortgage. Restrictions in the EDE mortgage bond indenture could affect our liquidity. The EDE Mortgage contains a requirement that for new first mortgage bonds to be issued, our net earnings (as defined in the EDE Mortgage) for any twelve consecutive months within the fifteen months preceding issuance must be two times the annual interest requirements (as defined in the EDE 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, 2008 would permit us to issue approximately $177.8 million of new first mortgage bonds based on this test with an assumed interest rate of 6.5%. In addition to the interest coverage requirement, the EDE Mortgage provides that new bonds must be issued against, among other things, retired bonds or 60% of net property additions. At June 30, 2008, we had retired bonds and net property additions which would enable the issuance of at least $562.0 million principal amount of bonds if the annual interest requirements are met. As of June 30, 2008, we are in compliance with all restrictive covenants of the EDE Mortgage.

Substantially all of the property, plant and equipment of The Empire District Gas Company is subject to the lien of the EDG Mortgage. The EDG Mortgage contains a requirement that for new first mortgage bonds to be issued, the amount of such new first mortgage bonds shall not exceed 75% of the cost of property additions acquired after the date of the Missouri Gas acquisition. At June 30, 2008, we had property additions of $3.1 million, which would enable the issuance of at least $2.3 million principal amount of bonds if the annual interest requirements are met. The mortgage also contains a limitation on the issuance by EDG of debt (including first mortgage bonds, but excluding short-term debt incurred in the ordinary course under working capital facilities) unless, after giving effect to such issuance, EDG’s ratio of EBITDA (defined as net income plus interest, taxes, depreciation, amortization and certain other non-cash charges) to interest charges for the most recent four fiscal quarters is at least 2.0 to 1. As of June 30, 2008, this test would allow us to issue new first mortgage bonds.

Currently, our corporate credit ratings and the ratings for our securities are as follows:

	Fitch	Moody’s	Standard & Poor’s
Corporate Credit Rating	n/r	Baa2	BBB-
First Mortgage Bonds	BBB+	Baa1	BBB+
First Mortgage Bonds - Pollution Control Series(1)	AAA	Aaa	AAA
Senior Unsecured Notes	BBB	Baa2	BB+
Trust Preferred Securities	BBB-	Baa3	BB
Commercial Paper	F2	P-2	A-3
Outlook	Negative	Negative	Stable

(1) Insured by a third party insurer.

On September 22, 2005, Standard & Poor’s (S&P), reflecting our announcement of our proposed acquisition of Aquila, Inc.’s Missouri natural gas properties, placed our corporate credit rating on credit watch with negative implications. S&P stated that the acquisition comes in addition to our embarking on a capital spending program that is significantly higher than historical levels and will be partially debt financed. On February 13, 2006, S&P removed our corporate credit rating from

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credit watch, but placed us on negative outlook. S&P also reduced the rating on our commercial paper from A-2 to A-3 on February 21, 2006. This reduction made it more difficult for us to issue commercial paper and, as a result, our short-term debt during the period from February 21, 2006 to June 30, 2006, was in the form of borrowings under our revolving credit facility. However, beginning on June 30, 2006, we were able to again issue commercial paper at the current rating under a new agreement with Wells Fargo Bank. On May 17, 2006, S&P lowered our long-term corporate credit rating to BBB- from BBB, senior secured debt to BBB+ from A-, senior unsecured debt rating to BB+ from BBB- and affirmed our short-term rating of A-3. S&P’s downgrade reflected their view that our financial measures will be constrained over the next several years by fuel and power costs that continue to exceed the level recoverable in rates, and by our higher-than-historical level of capital spending, including the acquisition of Missouri Gas. S&P affirmed our ratings on June 8, 2007 and again on June 12, 2008 with a stable outlook.

Moody’s affirmed our ratings on May 13, 2005 and revised their rating outlook on us from negative to stable. On January 24, 2007, Moody’s again affirmed our ratings but changed their rating outlook on us back to negative. The change to a negative rating outlook reflects Moody’s view on the longer-term prospects for our ratings given the sizable capital spending program we have committed to through 2010 and the potential for further weakness in our credit metrics that could develop during this time. On February 14, 2008, Moody’s placed all of our ratings on review for possible downgrade. Moody’s announced that the review would consider the cumulative impact that certain negative events, including severe weather and operational disruptions in 2007 and 2008, have had on our cash flow and overall financial flexibility at the current rating level as well as consider the potential for elevated costs related to our capital spending plan in 2008. On May 12, 2008, Moody’s affirmed our ratings with a negative outlook.

On December 19, 2005, Fitch Ratings initiated coverage and assigned ratings (see table above) with a stable rating outlook. Fitch announced that their ratings reflect our low business risk position as a regulated electric utility, a stable service territory and a seemingly improving regulatory environment in Missouri where we receive approximately 89% of our electric revenues. On January 25, 2008, Fitch affirmed our ratings but revised their rating outlook to negative. The change to a negative rating outlook reflects uncertainty surrounding the outcome of our current rate filing and weakness in our projected financial measures relative to Fitch guidelines for the rating category. Recent events leading to the revision were storm damage in December 2007 and the extended outage of the Asbury baseload coal plant following a failed generator inspection.

CONTRACTUAL OBLIGATIONS

Our contractual obligations have not significantly changed at June 30, 2008, compared to December 31, 2007 other than $90 million principal amount of first mortgage bonds issued May 16, 2008 and due 2018.

DIVIDENDS

Holders of our common stock are entitled to dividends if, as, and when declared by the Board of Directors, out of funds legally available therefore, subject to the prior rights of holders of any outstanding cumulative preferred stock and preference stock. Payment of dividends is determined by our Board of Directors after considering all relevant factors, including the amount of our retained earnings (which is essentially our accumulated net income less dividend payouts). As of June 30, 2008 our retained earnings balance was $7.4 million, compared to $13.8 million as of June 30, 2007, after paying out $10.8 million in dividends during the second quarter of 2008. A reduction of our dividend per share, partially or in whole, could have an adverse effect on our common stock price.

Our diluted earnings per share were $0.35 for the six months ended June 30, 2008 and were $1.09 and $1.39 for the years ended December 31, 2007 and 2006, respectively. Dividends paid per share were $0.64 for the six months ended June 30, 2008 and $1.28 for each of the years ended December 31, 2007 and 2006.

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In addition, the EDE Mortgage and our Restated Articles contain certain dividend restrictions. The most restrictive of these is contained in the EDE Mortgage, which provides that we may not declare or pay any dividends (other than dividends payable in shares of our common stock) or make any other distribution on, or purchase (other than with the proceeds of additional common stock financing) any shares of, our common stock if the cumulative aggregate amount thereof after August 31, 1944 (exclusive of the first quarterly dividend of $98,000 paid after said date) would exceed the sum of $10.75 million and the earned surplus (as defined in the EDE Mortgage) accumulated subsequent to August 31, 1944, or the date of succession in the event that another corporation succeeds to our rights and liabilities by a merger or consolidation. On March 11, 2008, we amended the EDE Mortgage in order to provide us with more flexibility to pay dividends to our shareholders by increasing the basket available to pay dividends by $10.75 million, as described above. As of June 30, 2008, this restriction did not prevent us from issuing dividends.

In addition, under certain circumstances, our Junior Subordinated Debentures, 8-1/2% Series due 2031, reflected as a note payable to securitization trust on our balance sheet, held by Empire District Electric Trust I, an unconsolidated securitization trust subsidiary, may also restrict our ability to pay dividends on our common stock. These restrictions apply if: (1) we have knowledge that an event has occurred that would constitute an event of default under the indenture governing these junior subordinated debentures and we have not taken reasonable steps to cure the event, (2) we are in default with respect to payment of any obligations under our guarantee relating to the underlying preferred securities, or (3) we have deferred interest payments on the Junior Subordinated Debentures, 8-1/2% Series due 2031 or given notice of a deferral of interest payments. As of June 30, 2008, there were no such restrictions on our ability to pay dividends.

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, other than operating leases entered into in the normal course of business.

CRITICAL ACCOUNTING POLICIES

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, 2007 for a discussion of our critical accounting policies. There were no changes in these policies in the quarter ended June 30, 2008.

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 typically includes 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 5 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 to commercial paper and borrowings under our unsecured credit agreement) to a certain percentage of total capitalization, as set by policy, and by monitoring the effects of market changes in interest rates.

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If market interest rates average 1% more in 2008 than in 2007, our interest expense would increase, and income before taxes would decrease by less than $0.4 million. This amount has been determined by considering the impact of the hypothetical interest rates on our highest month-end commercial paper balance for 2007. 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 satisfied 58.6% of our 2007 generation fuel supply need through coal. Approximately 86% of our 2007 coal supply was Western coal. We have contracts to supply fuel for our coal plants through 2010. These contracts and current inventory satisfy approximately 100% of our anticipated fuel requirements for 2008, 67% for 2009 and 48% for our 2010 requirements for our Asbury and Riverton coal plants. In order to manage our exposure to fuel prices, 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 18, 2008, 94%, or 3.4 million Dths’s, of our anticipated volume of natural gas usage for our electric operations for the remainder of 2008 is hedged.

Based on our expected natural gas purchases for our electric operations for the next twelve months, if average natural gas prices should increase 10% more than the price at June 30, 2008, our natural gas expense would increase, and income before taxes would decrease by approximately $1.2 million based on our June 30, 2008 total hedged positions for the next twelve months.

We attempt to mitigate a portion of our natural gas price risk associated with our gas segment using physical forward purchase agreements, storage and derivative contracts. As of July 17, 2008, we have 0.7 million Dths in storage on the three pipelines that serve our customers. This represents 36% of our storage capacity. Our long-term hedge strategy is to mitigate price volatility for our customers by hedging a minimum of 50% of current year, up to 50% of second year and up to 20% of third year expected gas usage by the beginning of the ACA year at September 1. However, due to purchased natural gas cost recovery mechanisms for our retail customers, fluctuations in the cost of natural gas have little effect on income.

Credit Risk. Credit risk is the risk of financial loss to the Company if counterparties fail to perform their contractual obligations. In order to minimize overall credit risk, we maintain credit policies, including the evaluation of counterparty financial condition and the use of standardized agreements that facilitate the netting of cash flows associated with a single counterparty. In addition, certain counterparties make available collateral in the form of cash held as margin deposits as a result of exceeding agreed-upon credit exposure thresholds or may be required to prepay the transaction. Amounts reported as margin deposit liabilities represent funds we hold that result from various trading counterparties exceeding agreed-upon credit exposure thresholds. Amounts reported as margin deposit assets represent funds held on deposit by various trading counterparties that resulted from us exceeding agreed-upon credit limits established by the counterparties.

The following table depicts our margin deposit assets and margin deposit liabilities at June 30, 2008 and December 31, 2007:

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(in millions)	June 30, 2008		December 31, 2007
Margin deposit assets	$	2.5	$	6.3
Margin deposit liabilities	$	17.8	$	—

In addition, we held a letter of credit from a counterparty in our favor for $6.5 million as of June 30, 2008.

We sell electricity and gas and provide distribution and transmission services to a diverse group of customers, including residential, commercial and industrial customers. Credit risk associated with trade accounts receivable from energy customers is limited due to the large number of customers. In addition, we enter into contracts with various companies in the energy industry for purchases of energy-related commodities, including natural gas in our fuel procurement process.

Our exposure to credit risk is concentrated primarily within our fuel procurement process, as we transact with a smaller, less diverse group of counterparties and transactions may involve large notional volumes and potentially volatile commodity prices. At July 18, 2008, gross credit exposure related to these transactions totaled $50.5 million ($19.8 million in physical contracts and $30.7 million in financial contracts), reflecting the unrealized gains for contracts carried at fair value.

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 (as such term is defined in Rule 13a-15(e) 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 as of June 30, 2008.

There have been no changes in our internal control over financial reporting that occurred during the second quarter of 2008 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II.  OTHER INFORMATION

Item 1A.  Risk Factors.

There have been no material changes to the factors disclosed in Part I, Item 1-A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2007.

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

(a)The Annual Meeting of Stockholders was held on April 24, 2008.

(b)The following persons were re-elected Directors of Empire to serve until the 2011 Annual Meeting of Stockholders:

William L. Gipson (26,323,753 votes for; 599,628 withheld authority).

Kenneth R. Allen (26,424,206 votes for; 499,175 withheld authority).

Bill D. Helton (26,374,762 votes for; 548,620 withheld authority).

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

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(c)Common stockholders voted to approve ratification of the appointment of PricewaterhouseCoopers LLP as Empire’s independent registered public accounting firm for the fiscal year ending December 31, 2008. Passage of the proposal required the affirmative vote of a majority of the votes cast. The proposal received 26,531,610 votes for and 247,390 votes against.

(d)Common stockholders were also asked to vote upon a non-binding advisory proposal to declassify our Board of Directors. The proposal received 12,036,642 votes for, 1,009,369 votes against, 1,157,832 abstentions and 12,719,539 broker non-votes.

Item 5.  Other Information.

For the twelve months ended June 30, 2008, our ratio of earnings to fixed charges was 2.09x.  See Exhibit (12) hereto.

Item 6.  Exhibits.

(a)Exhibits.

(10) Thirty-Third Supplemental Indenture, dated as of May 16, 2008, to the Indenture of      Mortgage and Deed of Trust dated as of September 1, 1944, as amended and supplemented, among the Company, The Bank of New York Trust Company, N.A. and UMB Bank & Trust, N.A. (Incorporated by reference to Exhibit 4.1 to the Current Report Form 8-K            dated May 16, 2008 and filed May 16, 2008, File No. 1-3368).

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

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

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

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

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

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

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SIGNATURES

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

THE EMPIRE DISTRICT ELECTRIC COMPANY
Registrant
By	/s/ Gregory A. Knapp
	Gregory A. Knapp
	Vice President – Finance and Chief Financial Officer
By	/s/ Laurie A. Delano
	Laurie A. Delano
	Controller, Assistant Secretary and Assistant Treasurer

August 7, 2008

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