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 September 30, 2007 or
o	Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the transition period from                       to                      .

Commission file number: 1-3368

THE EMPIRE DISTRICT ELECTRIC COMPANY

(Exact name of registrant as specified in its charter)

Kansas	44-0236370
(State of Incorporation)	(I.R.S. Employer Identification No.)
602 Joplin Street, Joplin, Missouri	64801
(Address of principal executive offices)	(zip code)

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

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

Indicate by check mark if the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Act. (Check one):

Large accelerated filer o Accelerated filer x Non-accelerated filer 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 November 1, 2007, 30,546,570 shares of common stock were outstanding.

THE EMPIRE DISTRICT ELECTRIC COMPANY

INDEX

	Forward Looking Statements
Part I -	Financial Information (Unaudited):
Item 1.	Consolidated Financial Statements:
	a.     Consolidated Statements of Operations
	b.     Consolidated Statements of Comprehensive Income
	c.     Consolidated Balance Sheets
	d.     Consolidated Statements of Cash Flows
	e.     Notes to Consolidated Financial Statements
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations
	Executive Summary
	Results of Operations
	Rate Matters
	Competition
	Liquidity and Capital Resources
	Contractual Obligations
	Dividends
	Off-Balance Sheet Arrangements
	Critical Accounting Policies
	Recently Issued Accounting Standards
Item 3.	Quantitative and Qualitative Disclosures About Market Risk
Item 4.	Controls and Procedures
Part II-	Other Information:
Item 1.	Legal Proceedings - (none)
Item 1A.	Risk Factors
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds - (none)
Item 3.	Defaults Upon Senior Securities - (none)
Item 4.	Submission of Matters to a Vote of Security Holders - (none)
Item 5.	Other Information
Item 6.	Exhibits
	Signatures

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 implementation of 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; and

•costs and effects of legal and administrative proceedings, settlements, investigations and claims.

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

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

3

PART I. FINANCIAL INFORMATION

Item 1. Consolidated Financial Statements

THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)

	Three Months Ended September 30
	2007			2006
	(000’s except per share amounts)
Operating revenues:
Electric	$	135,459		$	124,756
Gas	5,641			4,930
Water	521			553
Non-regulated	866			631
	142,487			130,870
Operating revenue deductions:
Fuel	36,974			33,780
Purchased power	15,428			14,756
Cost of natural gas sold and transported	2,607			2,222
Regulated – other	17,384			15,560
Non-regulated – other	357			355
Maintenance and repairs	6,669			5,846
Depreciation and amortization	13,368			9,829
Provision for income taxes	11,461			12,311
Other taxes	6,569			5,757
	110,817			100,416
Operating income	31,670			30,454
Other income and (deductions):
Allowance for equity funds used during construction	736			44
Interest income	72			105
Benefit/(provision) for other income taxes	1			(134		)
Other - non-operating expense	(200		)	(311		)
	609			(296		)
Interest charges:
Long-term debt	8,059			6,879
Note payable to securitization trust	1,063			1,063
Short-term debt	833			449
Allowance for borrowed funds used during construction	(1,117		)	(889		)
Other	241			280
	9,079			7,782
Income from continuing operations	23,200			22,376
Earnings (loss) from discontinued operations, net of tax	111			(24		)
Net income	$	23,311		$	22,352
Weighted average number of common shares outstanding - basic	30,481			30,120
Weighted average number of common shares outstanding - diluted	30,504			30,141
Earnings from continuing operations per weighted average share of common stock– basic and diluted	$	0.76		$	0.74
Earnings from discontinued operations per weighted average share of common stock – basic and diluted	$	0.00		$	0.00
Total earnings per weighted average share of common stock – basic and diluted	$	0.76		$	0.74
Dividends per share of common stock	$	0.32		$	0.32

See accompanying Notes to Consolidated Financial Statements.

4

THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)

	Nine Months Ended September 30,
	2007			2006
	(000’s except per share amounts)
Operating revenues:
Electric	$	329,900		$	296,159
Gas	41,670			6,557
Water	1,425			1,407
Non-regulated	2,391			1,819
	375,386			305,942
Operating revenue deductions:
Fuel	84,387			77,443
Purchased power	55,348			48,888
Cost of natural gas sold and transported	26,051			2,958
Regulated – other	52,958			42,982
Non-regulated – other	1,192			971
Maintenance and repairs	23,682			16,205
Depreciation and amortization	39,147			28,469
Provision for income taxes	15,893			17,505
Other taxes	19,022			15,259
	317,680			250,680
Operating income	57,706			$	55,262
Other income and (deductions):
Allowance for equity funds used during construction	2,294			166
Interest income	254			298
Benefit/(provision) for other income taxes	22			(82		)
Other - non-operating expense	(685		)	(752		)
	1,885			(370		)
Interest charges:
Long-term debt	23,063			19,069
Note payable to securitization trust	3,188			3,188
Short-term debt	2,175			1,701
Allowance for borrowed funds used during construction	(3,237		)	(1,844		)
Other	819			801
	26,008			22,915
Income from continuing operations	33,583			31,977
Earnings (loss) from discontinued operations, net of tax	63			(896		)
Net income	$	33,646		$	31,081
Weighted average number of common shares outstanding - basic	30,388			27,628
Weighted average number of common shares outstanding - diluted	30,409			27,645
Earnings from continuing operations per weighted average share of common stock– basic and diluted	$	1.11		$	1.15
Earnings (loss) from discontinued operations per weighted average share of common stock – basic and diluted	$	0.00		$	(0.03	)
Total earnings per weighted average share of common stock – basic and diluted	$	1.11		$	1.12
Dividends per share of common stock	$	0.96		$	0.96

See accompanying Notes to Consolidated Financial Statements.

5

THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)

	Twelve Months Ended
	September 30,
	2007			2006
	(000’s except per share amounts)
Operating revenues:
Electric	$	416,394		$	381,714
Gas	60,258			6,557
Water	1,861			1,770
Non-regulated	3,102			2,376
	481,615			392,417
Operating revenue deductions:
Fuel	100,899			105,606
Purchased power	72,799			65,571
Cost of natural gas sold and transported	38,378			2,959
Regulated – other	70,068			55,925
Non-regulated – other	1,558			1,299
Maintenance and repairs	30,626			21,918
Loss on plant disallowance	828			-
Depreciation and amortization	49,070			37,552
Provision for income taxes	20,335			18,125
Other taxes	24,790			19,921
	409,351			328,876
Operating income	72,264			63,541
Other income and (deductions):
Allowance for equity funds used during construction	3,533			361
Interest income	344			469
Benefit/(provision) for other income taxes	120			(102		)
Other – non-operating expense	(894		)	(983		)
	3,103			(255		)
Interest charges:
Long-term debt	29,941			25,008
Note payable to securitization trust	4,250			4,250
Short-term debt	2,750			1,726
Allowance for borrowed funds used during construction	(4,243		)	(1,949		)
Other	1,035			966
	33,733			30,001
Income from continuing operations	41,634			33,285
Earnings (loss) from discontinued operations, net of tax	211			(938		)
Net income	$	41,845		$	32,347
Weighted average number of common shares outstanding - basic	30,341			27,228
Weighted average number of common shares outstanding - diluted	30,361			27,244
Earnings from continuing operations per weighted average share of common stock– basic and diluted	$	1.37		$	1.22
Earnings (loss) from discontinued operations per weighted average share of common stock – basic and diluted	$	0.01		$	(0.03	)
Total earnings per weighted average share of common stock – basic and diluted	$	1.38		$	1.19
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
	September 30,
	2007			2006
	($-000’s)
Net income	$	23,311		$	22,352
Reclassification adjustments for gains included in net income or reclassified to regulatory asset or liability	(1,202		)	(463		)
Net change in fair market value of open derivative contracts for period	(7,071		)	(4,320		)
Income taxes	3,152			1,822
Net change in unrealized losses on derivative contracts	(5,121		)	(2,961		)
Comprehensive income	$	18,190		$	19,391

	Nine Months Ended
	September 30,
	2007			2006
	($-000’s)
Net income	$	33,646		$	31,081
Reclassification adjustments for gains included in net income or reclassified to regulatory asset or liability	(1,254		)	(1,268		)
Net change in fair market value of open derivative contracts for period	1,541			(12,693		)
Income taxes	(109		)	5,319
Net change in unrealized gain/(loss) on derivative contracts	178			(8,642		)
Comprehensive income	$	33,824		$	22,439

	Twelve Months Ended
	September 30,
	2007			2006
	($-000’s)
Net income	$	41,845		$	32,347
Reclassification adjustments for gains included in net income or reclassified to regulatory asset or liability	(1,306		)	(2,010		)
Net change in fair market value of open derivative contracts for period	629			(16,827		)
Income taxes	258			7,143
Net change in unrealized losses on derivative contracts	(419		)	(11,694		)
Comprehensive income	$	41,426		$	20,653

See accompanying Notes to Consolidated Financial Statements

7

THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS (UNAUDITED)

	September 30, 2007		December 31, 2006
	($-000’s)
Assets
Plant and property, at original cost:
Electric	$	1,399,834	$	1,291,533
Gas	54,130		51,936
Water	10,052		10,126
Non-regulated	23,239		21,242
Construction work in progress	139,631		111,918
	1,626,886		1,486,755
Accumulated depreciation and amortization	489,818		456,635
	1,137,068		1,030,120
Current assets:
Cash and cash equivalents	6,312		12,303
Accounts receivable – trade, net	45,002		33,477
Accrued unbilled revenues	14,602		14,866
Accounts receivable – other	13,748		13,217
Fuel, materials and supplies	46,873		46,613
Unrealized gain in fair value of derivative contracts	3,131		3,819
Prepaid expenses	4,129		3,711
Discontinued operations	—		94
	133,797		128,100
Noncurrent assets and deferred charges:
Regulatory assets	91,935		94,395
Goodwill	39,492		39,323
Unamortized debt issuance costs	6,778		6,044
Unrealized gain in fair value of derivative contracts	13,482		11,812
Other	4,353		5,221
Discontinued operations	—		873
	156,040		157,668
Total Assets	$	1,426,905	$	1,315,888

(Continued)

See accompanying Notes to Consolidated Financial Statements

8

	September 30, 2007		December 31, 2006
	($-000’s)
Capitalization and Liabilities
Common stock, $1 par value, 30,529,934 and 30,250,566 shares issued and outstanding, respectively	$	30,530	$	30,251
Capital in excess of par value	412,540		406,650
Retained earnings	27,332		22,916
Accumulated other comprehensive income, net of income tax	8,969		8,792
Total common stockholders’ equity	479,371		468,609
Long-term debt:
Note payable to securitization trust	50,000		50,000
Obligations under capital lease	390		512
First mortgage bonds and secured debt	242,949		163,088
Unsecured debt	248,593		248,798
Total long-term debt	541,932		462,398
Total long-term debt and common stockholders’ equity	1,021,303		931,007
Current liabilities:
Accounts payable and accrued liabilities	47,586		51,712
Current maturities of long-term debt	148		141
Short-term debt	67,745		77,050
Customer deposits	7,981		7,239
Interest accrued	10,706		3,889
Unrealized loss in fair value of derivative contracts	1,761		1,372
Taxes accrued	13,498		2,744
Other current liabilities	1,359		1,790
Discontinued operations	—		174
	150,784		146,111
Commitments and contingencies (Note 8)
Noncurrent liabilities and deferred credits:
Regulatory liabilities	53,977		49,822
Deferred income taxes	154,643		140,838
Unamortized investment tax credits	3,502		3,971
Pension and other postretirement benefit obligations	21,734		26,458
Unrealized loss in fair value of derivative contracts	1,299		—
Other	19,663		17,496
Discontinued operations	—		185
	254,818		238,770
Total Capitalization and Liabilities	$	1,426,905	$	1,315,888

See accompanying Notes to Consolidated Financial Statements.

9

THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

	Nine Months Ended
	September 30,
	2007			2006
	($-000’s)
Operating activities:
Net income	$	33,646		$	31,081
Adjustments to reconcile net income to cash flows from operating activities:
Depreciation and amortization	43,072			31,900
Pension and postretirement benefit costs	7,027			4,108
Deferred income taxes and investment tax credit, net	9,636			547
Allowance for equity funds used during construction	(2,294		)	(166		)
Stock compensation expense	1,922			1,482
Unrealized gain on derivatives	(942		)	(2,835		)
Gain on the sale of non-regulated businesses	(161		)	(272		)
Cash flows impacted by changes in:
Accounts receivable and accrued unbilled revenues	(12,733		)	7,049
Fuel, materials and supplies	(260		)	(6,359		)
Prepaid expenses, other current assets and deferred charges	43			(5,260		)
Accounts payable and accrued liabilities	(3,915		)	(21,613		)
Interest, taxes accrued and customer deposits,	18,225			21,601
Other liabilities and other deferred credits	(4,890		)	1,127
Net cash provided by operating activities of continuing operations	88,376			62,390
Net cash provided by operating activities of discontinued operations	208			1,819
Net cash provided by operating activities	88,584			64,209
Investing activities:
Capital expenditures – regulated	(138,681		)	(86,835		)
Acquisition of gas operations	—			(103,193		)
Capital expenditures and other investments – non-regulated	(3,223		)	(2,125		)
Proceeds from the sale of non-regulated businesses	3,240			1,095
Net cash used in investing activities of continuing operations	(138,664		)	(191,058		)
Net cash used in investing activities of discontinued operations	(12		)	(377		)
Net cash used in investing activities	(138,676		)	(191,435		)
Financing activities:
Proceeds from first mortgage bonds - electric	79,831			—
Proceeds from first mortgage bonds - gas	—			55,000
Long-term debt issuance costs	(1,078		)	(748		)
Proceeds from issuance of common stock net of issuance costs	4,272			78,252
Net short-term (repayments) borrowings	(9,305		)	9,798
Dividends	(29,176		)	(26,394		)
Other	(375		)	(377		)
Net cash provided by financing activities of continuing operations	44,169			115,531
Net cash used in financing activities of discontinued operations	(68		)	(374		)
Net cash provided by financing activities	44,101			115,157
Net decrease in cash and cash equivalents	(5,991		)	(12,069		)
Cash and cash equivalents at beginning of period	12,303			15,892
Cash and cash equivalents at end of period	$	6,312		$	3,823

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 consists of our non-regulated businesses, primarily, a 100% interest in Empire District Industries, Inc., a subsidiary for our fiber optics business.

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, 2006.

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, 2006. Certain reclassifications have been made to prior year information to conform to the current year presentation.

The Missouri Public Service Commission (MPSC) issued an order pertaining to our electric segment on December 21, 2006 granting us an annual increase of $29.4 million (including regulatory amortization), or 9.96%, with an effective date of January 1, 2007. The accounting treatment in this order includes regulatory amortization which provides us additional cash flow through rates to begin recovery of costs associated with our current generation expansion. This regulatory amortization was $7.9 million for the first nine months of 2007 and has been recorded as depreciation expense. Additionally, the MPSC adopted an agreement of the parties to continue to allow the recording of pension expense above or below the amount allowed in rates to a regulatory asset or liability, respectively. This mechanism, commonly referred to as a tracker, was also established for our other postretirement benefit expenses. Please see Notes 4 and 9 for further discussion of pension and other postretirement benefit regulatory treatment.

On February 1, 2007, the Southwest Power Pool (SPP) regional transmission organization (RTO) launched its Energy Imbalance Services (EIS) market. The EIS market is monitored by our Wholesale Energy group. Sales and purchase transactions are netted on an hourly basis to determine if we are a net seller or a net purchaser. Net sales are recorded as off-system sales while net purchases are recorded as purchased power.

A major ice storm struck virtually all areas of our electric service territory January 12-14, 2007 causing substantial damage. Approximately 85,000 (52%) of our electric customers were without power at the height of the storm. Costs associated with the restoration effort due to the ice storm were approximately $30.7 million, of which $19.2 million has been capitalized as additions to our utility plant, approximately $4.6 million recorded as maintenance expense and approximately $6.9 million was deferred as a regulatory asset as we believe it is probable that these costs will be recoverable in future electric rate cases.

Note 2 - Recently Issued Accounting Standards

On September 15, 2006, the FASB issued FASB No. 157, “Fair Value Measurements” (FAS 157), which provides guidance for using fair value to measure assets and liabilities. FAS 157 also responds to investors’ requests for more information about (1) the extent to which companies measure assets and liabilities at fair value, (2) the information used to measure fair value and (3) the effect that fair-value measurements have on earnings. FAS 157 will apply whenever another

11

standard requires (or permits) assets or liabilities to be measured at fair value. This standard does not expand the use of fair value to any new circumstances. FAS 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007 and interim periods within those fiscal years. We have not yet completed our review regarding the impact of the adoption of this standard; however, we do not expect the adoption of this standard to have a material impact on our financial statements.

On February 15, 2007, the FASB issued FASB 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. We have not yet completed our review regarding the impact of the adoption of this standard; however, we do not expect the adoption of this standard to have a material impact on our financial statements.

See Note 1 under “Notes to Consolidated Financial Statements” in our Annual Report on Form 10-K for the year ended December 31, 2006 for further information regarding recently issued accounting standards.

Note 3 – FASB Interpretation No. 48 (FIN 48) – Accounting for Uncertainty in Income Taxes

On July 13, 2006, the FASB issued FIN 48, which clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with FASB Statement No. 109, “Accounting for Income Taxes.” We file consolidated income tax returns in the U.S. federal and state jurisdictions. With few exceptions, we are no longer subject to U.S. federal, state and local, or non-U.S. income tax examinations by tax authorities for years before 2003. We adopted the provisions of FIN 48 on January 1, 2007. As a result of the implementation of FIN 48, we recognized approximately $54,000 of additional liability for unrecognized tax benefits, which was accounted for as a reduction to the January 1, 2007 balance of retained earnings. At January 1, 2007 and September 30, 2007, our balance sheet included approximately $219,000 and $314,000, respectively, of unrecognized tax benefits which would affect our effective tax rate if recognized. We do not expect any material changes to unrecognized tax benefits within the next twelve months. We recognize interest accrued and penalties related to unrecognized tax benefits in other expenses.

Note 4– 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)	September 30, 2007		December 31, 2006
Regulatory Assets:
Income taxes	$	29,475	$	27,893
Unamortized loss on reacquired debt	15,144		16,136
Unamortized loss on interest rate derivative	2,798		3,035
Pension and other postretirement benefits (1)	31,939		40,145
Asset retirement obligation	3,036		3,022
Unrecovered purchased gas costs and Kansas fuel costs	1,740		3,024
Ice storm costs	6,907		—
Other	896		1,140
Total	$	91,935	$	94,395

12

(In thousands)	September 30, 2007		December 31, 2006
Regulatory Liabilities:
Income taxes	$	10,214	$	12,100
Unamortized gain on interest rate derivative	4,434		4,561
Gain on disposition of emission allowances	363		361
Cost of removal	34,415		31,461
Pensions and other postretirement benefits	4,159		1,339
Kansas fuel costs	392		—
Total	$	53,977	$	49,822

(1) Primarily reflects regulatory assets resulting from the adoption of FAS 158 (including a $5.6 million decrease in our liability for Other Postretirement Benefits) and regulatory accounting for EDG acquisition costs.

Pension and Other Postretirement Benefits:  As discussed in Note 1, effective January 1, 2007, the MPSC granted regulatory treatment for our other postretirement benefit costs similar to the treatment already in place for our pension costs. We now recognize a regulatory asset or liability, along with corresponding decreases or increases in expense, respectively, for actuarial 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, 2007, approximately $2.8 million in additional regulatory liabilities and corresponding expense increases have been recognized.

In addition, approximately $0.4 million in pension and other postretirement benefit costs have been recognized since January 1, 2007 to reflect the amortization of the regulatory assets that were recorded at the time of the acquisition of the Aquila, Inc. gas properties. These regulatory assets reflect that the purchase accounting entries related to pension and other postretirement benefit costs were allowed to be ignored for ratemaking purposes, as they will be recovered in future rates.

Note 5– Acquisition of Missouri Natural Gas Distribution Operations

On September 21, 2005, we announced that we had entered into an Asset Purchase Agreement with Aquila, Inc., pursuant to which we agreed to acquire the Missouri natural gas distribution operations of Aquila, Inc. This acquisition was completed by our wholly-owned subsidiary, The Empire District Gas Company (EDG), on June 1, 2006. This transaction was subject to the approval of the MPSC, which was obtained, effective May 1, 2006. The total purchase price, including working capital and net plant adjustments but excluding acquisition costs, was $102.5 million. We recorded $39.5 million of goodwill as a result of the acquisition. All of this goodwill is expected to be tax deductible.

The components of the purchase price allocation for the Missouri Gas acquisition are shown below. Assets and liabilities were valued at fair value. In the case of property, plant and equipment, fair value was calculated in a manner consistent with the amount recoverable for regulatory treatment.

(In thousands)	Missouri Gas
Purchase Price:
Cash paid	$	102,502
Acquisition costs	2,447
Total	$	104,949
Allocation:
Property, plant and equipment	$	52,226
Current assets	15,292
Goodwill	39,492
Other assets	11,082
Other liabilities	(13,143		)
Total	$	104,949

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The following presents certain consolidated proforma financial information for the nine months and twelve months ended September 30, 2006, as if our acquisition of Missouri Gas had been completed as of October 1, 2005. These estimates are based on historical results of the Missouri Gas operations, provided to us by Aquila, Inc., and are unaudited.

	Nine Months Ended		Twelve Months Ended
($-000’s except per share amounts)	2006		2006
Revenues	$	335,586	$	443,692
Net income from continuing operations	33,535		35,988
Earnings per share from continuing operations -basic and diluted	$	1.15	$	1.21

Note 6– Risk Management and Derivative Financial Instruments

Electric

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

A $9.0 million net of tax, unrealized gain representing the fair market value of derivative contracts treated as cash flow hedges is recognized as Accumulated Other Comprehensive Income in the capitalization section of the balance sheet as of September 30, 2007. The tax effect of $5.5 million on this gain is included in deferred taxes. These amounts will be adjusted cumulatively on a monthly basis during the determination periods, beginning October 1, 2007 and ending on September 30, 2011. At the end of each determination period, or if cash flow hedge treatment is discontinued, any gain or loss for that period related to the instrument will be reclassified to fuel expense.

As of June 30, 2007, we elected to change our valuation of natural gas derivatives (financial hedges) for financial reporting purposes to a new methodology which is more closely related to an independent market valuation. For accounting purposes, this change is considered a change in estimate. To reflect the change, an approximate $6 million increase was recorded to the fair value of derivatives and $3.7 million, net of tax, was recorded to other comprehensive income at June 30, 2007. This change had no impact on the income statement.

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 electric generation and the actual pre-tax gains/(losses) from the qualified portion of our hedging activities for settled contracts included in “Fuel” for each of the periods ended September 30:

	Three months ended				Nine months ended					Twelve months ended
(In thousands)	2007		2006		2007		2006			2007		2006
Ineffective Portion	$	—	$	—	$	—	$	(34	)	$	—	$	(223	)
Qualified Portion	$	1,202	$	463	$	1,254	$	1,268		$	1,306	$	2,010

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.

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As of October 26, 2007, 88% of our anticipated volume of natural gas usage for our electric operations for the remainder of year 2007 is hedged, either through physical or financial contracts, at an average price of $7.037 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 six years are hedged at the following average prices per Dth:

Year	% Hedged		Dth Hedged	Average Price
2008	89	%	7,676,000	$	6.849
2009	54	%	4,696,000	$	6.060
2010	40	%	3,696,000	$	5.422
2011	39	%	3,696,000	$	5.422
2012	13	%	1,200,000	$	7.295
2013	13	%	1,200,000	$	7.295

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. As of October 26, 2007, we have 92% of our expected upcoming winter heating season usage (November 2007 through March 2008) hedged with physical storage, physical forward contracts and financial derivative contracts. The average price of these hedges is $5.405 per Dth. We target to have 95% of our storage capacity full by November 1 for the upcoming winter heating season. As of November 1, 2007, we had 1.8 million Dths in storage on the three pipelines that serve our customers, which was 0.08 million Dths below our 95% target. Our long-term hedge positions for gas purchased for resale are still in the development process. 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.

Note 7– Financing

On March 26, 2007, EDE issued $80 million principal amount of First Mortgage Bonds, 5.875% Series due 2037. The net proceeds of $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 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 $47.5 million as of November 1, 2007. 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 September 30, 2007, we are in compliance with these ratios. This credit facility is also subject to cross-default if we default on in excess of $10

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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 September 30, 2007, however, $67.7 million of the availability thereunder was used at such date to back up our outstanding commercial paper.

Note 8– 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 $60.1 million for October 1, 2007 through September 30, 2008, $49.5 million for October 1, 2008 through September 30, 2010, $46.1 million for October 1, 2010 through September 30, 2012 and $78.0 million for October 1, 2012 and beyond. In the event that this gas cannot be used at our plants, the gas would 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. The minimum requirements are $23.7 million for October 1, 2007 through September 30, 2008, $33.2 million for October 1, 2008 through September 30, 2010 and $1.8 million for October 1, 2010 through September 30, 2012.

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 $43.2 million through May 31, 2010.

We also have a long term 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 100-megawatt Phase 1 Meridian Wind Farm to be located in Cloud County, Kansas and a 20-year contract with Elk River Windfarm, LLC, owned by PPM Energy, to purchase the energy generated at the 150-megawatt Elk River Windfarm located in Butler County, Kansas. Although these agreements are considered operating leases under GAAP, payments for these

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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 $103.0 million, including AFUDC. In addition, we entered into an agreement with Kansas City Power & Light (KCP&L) on June 13, 2006 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. We expect our share of the Iatan 2 construction costs will range from approximately $183.6 million to $200.5 million, excluding AFUDC.

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 100-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 supply 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 five service center properties for our gas segment. In addition we have a five-year capital lease for telephone equipment.

Our lease obligations over the next five years are as follows:

(In thousands)	Capital Leases
2007	$	288
2008	288
2009	288
2010	28
2011	—
Thereafter	—
Total minimum payments	$	892
Less amount representing maintenance	298
Net minimum lease payments	594
Less amount representing interest	56
Present value of net minimum lease payments	$	538

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(In thousands)	Operating Leases
2007	$	1,524
2008	931
2009	288
2010	269
2011	156
Thereafter	715
Total minimum payments	$	3,883

The accumulated amount of amortization for our capital leases was $0.2 million at September 30, 2007.

The following table represents our operating lease expense for the applicable periods ended September 30:

	Three Months Ended				Nine months Ended				Twelve Months Ended
(in thousands)	2007		2006		2007		2006		2007		2006
Operating lease expense	$	348	$	235	$	1,051	$	655	$	1,304	$	845

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, including asbestos, 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). The Asbury Plant became an affected unit under the 1990 Amendments for SO2 on January 1, 1995 and for NOx as a Group 2 cyclone-fired boiler on January 1, 2000. The Iatan Plant became an affected unit for both SO2 and NOx on January 1, 2000. The Riverton Plant became an affected unit for NOx in November 1996 and for SO2 on January 1, 2000. The State Line Plant became an affected unit for SO2 and NOx on January 1, 2000. Units 3 and 4 at the Empire Energy Center became affected units for both SO2 and NOx in April 2003. The new Riverton Unit 12 became an affected unit in January 2007.

SO2 Emissions. Under the 1990 Amendments, the amount of SO2 an affected unit can emit is regulated. Each existing affected unit has been awarded 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. 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 awarded 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 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 Riverton Plant can also burn natural gas as its primary fuel. The State Line Plant, the Energy Center Units 3 and 4 and the new 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 2006, the combined actual SO2 allowance need for all affected plant facilities exceeded the number of allowances awarded to us by the EPA, therefore, as of December 31, 2006, we had 31,000 banked SO2 allowances as compared to 41,000 at December 31, 2005. Based on current SO2 allowance usage projections,

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we will need to construct a sulfur scrubber at Asbury, modify coal blends or purchase additional SO2 allowances sometime around 2012.

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.

SO2 emissions will be further regulated as described in the Clean Air Interstate Rule section below.

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 2006, approximately 5,794 tons of TDF were burned. This is equivalent to 579,400 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. However, facilities which burn at least 100,000 passenger tire equivalents of TDF per year, including our Asbury Plant, are only 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.

NOx is further regulated as described in the Clean Air Interstate Rule below.

Clean Air Interstate Rule (CAIR)

The EPA issued its final CAIR on March 10, 2005. CAIR governs NOx and SO2 emissions from fossil fueled units greater than 25 megawatts and will affect 28 states, including Missouri, where our Asbury, Energy Center, State Line and Iatan Plants are located and Arkansas where the future Plum Point Energy Station will be located.

The CAIR is not directed to specific generation units, but instead, requires the states (including Missouri and Arkansas) to develop State Implementation Plans (SIPs) to comply with specific NOx and SO2 state-wide annual budgets. Missouri and Arkansas finalized their respective regulations and submitted their SIPs to the EPA for approval. The EPA has published their proposal to approve the Missouri and Arkansas SIPs in the Federal Register. Until these SIPs are approved by the EPA, we cannot definitively determine the allowed emissions of NOx and SO2 for the Asbury, Energy Center, State Line and Iatan Plants in Missouri or the Plum Point Energy Station in Arkansas. However, based on the submitted SIPs, it appears we will have excess NOx allowances. SO2 allowances must be utilized at a 2:1 ratio for our Missouri units as compared to our non-CAIR Kansas units beginning in 2010. Based on current SO2 allowance usage projections, we will need to construct a sulfur scrubber at our Asbury plant, modify coal blends or purchase additional SO2 allowances sometime around 2012.

In order to help meet anticipated CAIR requirements and to meet air permit requirements for Iatan Unit 2, we are installing pollution control equipment on Iatan Unit 1 which will be completed around the end of 2008. This equipment includes a Selective Catalytic Reduction (SCR) system, a Flue Gas Desulphurization (FGD) system and a baghouse, with our share of the capital cost estimated at $46 million, excluding AFUDC. Of this amount, approximately $3.9 million was incurred in 2006. Approximately $14.0 million in 2007, $26.7 million in 2008, $1.4 million in 2009 and $0.3 million in 2010 are included in our current capital expenditures budget. These projects were included as part of our Experimental Regulatory Plan approved by the MPSC.

Also to help meet anticipated CAIR requirements, we are constructing an SCR at Asbury. We expect the SCR to be in service by January of 2008. We have awarded a contract and the

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SCR is under construction and is currently being tied into the existing unit during our major turbine inspection outage in progress at the Asbury plant. Our Asbury units went off-line September 21, 2007 and are expected to be back on-line during the last week of November. As of September 30, 2007, we have spent $27.8 million (including AFUDC) on the SCR at Asbury, which is also included in our current capital expenditures budget. This project was also included as part of our Experimental Regulatory Plan approved by the MPSC.

We also expect that additional pollution control equipment to comply with CAIR may become economically justified at the Asbury Plant sometime prior to 2015 and may include a FGD to control SO2 and a baghouse at an estimated capital cost of $100 million. At this time, we do not anticipate the installation of additional pollution control equipment at the Riverton Plant.

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 will go into effect January 1, 2010.

The CAMR is not directed to specific generation units, but instead, requires the states (including Missouri, Kansas and Arkansas) to develop SIPs to comply with specific mercury state-wide annual budgets. Missouri, Kansas and Arkansas have finalized their respective regulations and submitted their SIPs to the EPA. Until their SIPs are approved, we cannot definitively determine the allowed emissions for mercury for the Asbury, Energy Center, State Line and Iatan Plants in Missouri, the Plum Point Energy Station in Arkansas or the Riverton Plant in Kansas. The proposed SIPs for all states include allowance trading programs for mercury that could allow compliance without additional capital expenditures.

Based on initial testing and the submitted SIPs, we believe we will be granted enough mercury allowances on January 1, 2010 in aggregate to meet our anticipated mercury emissions. We are adding mercury analyzers at Asbury during 2007 and 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 mercury emission compliance date of January 1, 2010.

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. We continue to assess the financial and operational risks posed by possible future legislative changes pertaining to greenhouse gas emissions, but because these proposals are in the formative stages, we are unable to predict any future impacts on our financial conditions and operations.

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.

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The Riverton Plant is affected by final regulations for Cooling Water Intake Structures issued under the Clean Water Act Section 316(b) Phase II. The regulations became final on February 16, 2004 and require the submission of a Comprehensive Demonstration Study with the permit renewal in 2008. A Proposal for Information Collection (PIC) has been 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 a summary report will be completed by December 2007. 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 in 2008. If this occurs, we will monitor the EPA revision process and comment appropriately. Data collection and analysis will continue under the PIC and will be expanded as needed to limit increased costs, if any, due to the EPA’s suspension and revision of the regulation. The permit renewal application will be prepared and submitted as scheduled following KDHE guidance. Under the initial 316(b) regulations, we did not expect costs associated with compliance to be material. We will assess costs under revised rules when they 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 is 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 the to-be-constructed Iatan Unit No. 2. 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 late in the fourth quarter of 2008.

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 (the MDNR Registry). 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.

Note 9 – Pension and Other Postretirement Benefits

The components of our net periodic cost of pension (expensed and capitalized) and other postretirement benefits are summarized below:

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	Pension Benefits						Other Postretirement Benefits
	Three months ended September 30,
(in thousands)	2007			2006			2007			2006
Service cost	$	869		$	785		$	228		$	360
Interest cost	2,036			1,980			612			824
Expected return on plan assets	(2,554		)	(2,507		)	(683		)	(725		)
Amortization of prior service cost (1)	157			135			(508		)	(147		)
Amortization of net actuarial loss (1)	651			834			264			600
Net periodic benefit cost	$	1,159		$	1,227		$	(87	)	$	912
Regulatory adjustments (2)	518			175			901			32
Adjusted pension and OPEB cost	$	1,677		$	1,402		$	814		$	944

	Pension Benefits						Other Postretirement Benefits
	Nine months ended September 30,
(in thousands)	2007			2006			2007				2006
Service cost	$	2,619		$	2,552		$	1,278			$	1,362
Interest cost	6,124			5,549			2,562				2,485
Expected return on plan assets	(7,729		)	(6,986		)	(2,333			)	(2,080			)
Amortization of prior service cost (1)	344			335			(758			)	(347			)
Amortization of net actuarial loss (1)	1,951			2,485			864				1,800
Net periodic benefit cost	3,309			3,935			1,613				3,220
Regulatory adjustments (2)	1,926			(279		)	1,651				60
Adjusted pension and OPEB cost	$	5,235		$	3,656		$		3,264		$		3,280

	Pension Benefits						Other Postretirement Benefits
	Twelve months ended September 30,
(in thousands)	2007			2006			2007			2006
Service cost	$	3,470		$	3,569		$	1,782		$	1,828
Interest cost	8,047			7,427			3,503			3,231
Expected return on plan assets	(10,256		)	(9,274		)	(3,035		)	(2,613		)
Amortization of prior service cost (1)	457			479			(873		)	(484		)
Amortization of transition obligation	—			—			—			244
Amortization of net actuarial loss (1)	2,786			3,311			1,462			2,232
Net periodic benefit cost	$	4,504		$	5,512		$	2,839		$	4,438
Regulatory adjustments (2)	2,361			(675		)	1,791			60
Adjusted pension and OPEB cost	$	6,865		$	4,837		$	4,630		$	4,498

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

(2) Reflects the effect of regulatory accounting as discussed in Note 4.

Based on the performance of our pension plan assets through January 1, 2006 and 2007, we were not required under the Employee Retirement Income Security Act of 1974 (ERISA) to fund any additional minimum ERISA amounts with respect to 2006 or 2007.

We have made other postretirement benefit contributions of $3.0 million in 2007, which satisfies all of our 2007 funding requirements.

Note 10 – 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 September 30:

	Three Months Ended				Nine months Ended				Twelve Months Ended
(in thousands)	2007		2006		2007		2006		2007		2006
Compensation Expense	$	400	$	361	$	1,666	$	1,299	$	2,037	$	1,606
Tax Benefit Recognized	143		129		608		467		740		575

Activity for our various stock plans for the nine months ended September 30, 2007 is summarized below:

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Performance-Based Restricted Stock Awards

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

	2007	2006
Risk-free interest rate	5.09% to 4.88%	4.60% to 4.54%
Expected volatility of Empire stock	16.6%	15.2%
Expected volatility of peer group stock	18.9%	19.8%
Expected dividend yield on Empire stock	5.55%	5.80%
Expected forfeiture rates	3%	3%
Plan cycle	3 years	3 years
EDE percentile performance	25th	33rd
Fair value percentage	107.73%	108.13%
Grant date	1/31/2007	2/01/2006
Grant date fair value per share	$ 25.65	$ 24.04

Non-vested restricted stock awards (based on target number) as of September 30, 2007 and 2006 and changes during the nine months ended September 30, 2007 and 2006 were as follows:

	YTD 2007				YTD 2006
	Number of shares		Weighted Average Grant Date Price		Number of shares		Weighted Average Grant Date Price
Nonvested at January 1,	38,800		$	22.25	40,300		$	20.76
Granted	17,700		$	23.81	13,600		$	22.23
Awarded	(7,598	)	$	21.79	(7,954	)	$	18.25
Not Awarded	(5,502	)			(7,146	)
Nonvested at September 30,	43,400		$	23.02	38,800		$	22.25

At September 30, 2007, there was $0.5 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 nine months ended September 30, 2007 and 2006 is presented below:

		Weighted Average			Weighted Average
	2007	Exercise		2006	Exercise
	Options	Price		Options	Price
Outstanding at January 1,	135,000	$	22.21	142,500	$	20.84
Granted	64,200	$	23.81	41,700	$	22.23
Exercised	50,000	$	21.79	49,200	$	18.25
Outstanding at September 30, (1)	149,200	$	23.04	135,000	$	22.21

(1) 2007 includes 4,200 shares at weighted average price of $21.79, which are vested and exercisable. All others are non-vested.

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The aggregate intrinsic value at September 30, 2007 and 2006 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 range of exercise prices for the options outstanding at September 30, 2007 was $21.79 to $23.81. The weighted-average remaining contractual life of outstanding options at September 30, 2007 and 2006 was 7.8 years and 8.3 years, respectively. As of September 30, 2007, 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
	2007			2006
Weighted average fair value of grants	$	2.38		$	1.65
Risk-free interest rate	4.68		%	3.27		%
Dividend yield	5.33		%	6.16		%
Expected volatility	16.13		%	18.14		%
Expected life in months	60			60
Grant Date	1/31/07			2/1/06

Employee Stock Purchase Plan

Our Employee Stock Purchase Plan (ESPP) permits the grant of options to purchase common stock to eligible employees at 90% of the lower of market value at date of grant or at date of exercise. The lookback feature of this plan is ultimately valued at 90% of the lookback feature valued under the Black-Scholes methodology plus 10% of the maximum subscription price. As of September 30, 2007, there were 480,812 shares available for issuance in this plan. The following table has been updated through the third quarter.

	2007			2006
Subscriptions outstanding at September 30	41,112			39,986
Maximum subscription price	$	21.23	(1)	$	20.05
Shares of stock issued	37,686			39,322
Stock issuance price	$	20.05		$	19.62

(1) Stock will be issued on the closing date of the purchase period, which runs from June 1, 2007 to May 31, 2008.

Assumptions for valuation of these shares using the Black-Scholes methodology are shown in the table below.

	ESSP
	Nine months ended
	2007			2006
Weighted average fair value of grants	$	3.40		$	3.19
Risk-free interest rate	4.98		%	5.02		%
Dividend yield	5.43		%	5.75		%
Expected volatility	18.01		%	18.30		%
Expected life in months	12			12
Grant Date	6/1/07			6/1/06

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Note 11 – Regulated Other Operating Expense

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

(in thousands)	Three Months Ended 2007		Three Months Ended 2006		Nine months Ended 2007		Nine months Ended 2006		Twelve Months Ended 2007		Twelve Months Ended 2006
Electric transmission and distribution expense	$	2,545	$	2,052	$	6,924	$	6,040	$	9,248	$	8,036
Natural gas transmission and distribution expense	419		416		1,287		539		1,791		539
Power operation expense (other than fuel)	2,704		2,513		7,689		7,122		10,167		9,775
Customer accounts and assistance expense	2,416		2,184		6,756		5,869		9,165		7,639
Employee pension expense (1)	1,603		1,196		4,993		2,990		6,197		3,260
Employee healthcare plan (1)	1,875		1,780		6,079		5,449		8,294		7,285
General office supplies and expense	2,521		2,073		7,690		5,790		9,854		7,672
Administrative and general expense	2,739		2,996		8,218		7,926		11,153		9,952
Allowance for uncollectible accounts	525		304		3,191		1,173		4,015		1,643
Miscellaneous expense	37		46		131		84		184		124
Total	$	17,384	$	15,560	$	52,958	$	42,982	$	70,068	$	55,925

(1) Includes effects of regulatory treatment for pension and other postretirement benefits but does not include capitalized portion.

Note 12 – 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 of our non-regulated businesses, primarily, a 100% interest in Empire District Industries, Inc., a subsidiary for our fiber optics business.

We sold our controlling 52% interest in Mid-America Precision Products (MAPP) on August 31, 2006, a company that specializes in close-tolerance custom manufacturing for the aerospace, electronics, telecommunications and machinery industries. In December 2006, we sold our interest in Conversant, Inc., a software company that markets 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, these businesses, all of which were formerly within our other segment, have been classified as a discontinued operation and are not included in our segment information.

The tables below present information about the revenues, operating income, income from continuing operations, capital expenditures and total assets of our business segments.

	For the quarter ended September 30,
	2007
($-000’s)	Electric		Gas			Other		Eliminations			Total
Statement of Income Information
Revenues	$	135,980	$	5,641		$	987	$	(121	)	$		142,487
Operating income (loss)	31,427		(39		)	282					31,670
Income (loss) from continuing operations	24,015		(907		)	92					23,200
Capital Expenditures	$	49,067	$	825		$	1,412				$	51,304

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	For the quarter ended September 30,
	2006
($-000’s)	Electric		Gas			Other		Eliminations			Total
Statement of Income Information
Revenues	$	125,309	$	4,930		$	728	$	(97	)	$	130,870
Operating income (loss)	30,494		(139		)	99					30,454
Income (loss) from continuing operations	23,418		(1,113		)	71					22,376
Capital Expenditures	33,418		1,205			553					35,176

	For the nine months ended September 30,
	2007
($-000’s)	Electric		Gas		Other		Eliminations			Total
Statement of Income Information
Revenues	$	331,325	$	41,670	$	2,705	$	(314	)	$	375,386
Operating income	54,403		2,663		640					57,706
Income from continuing operations	33,451		20		112					33,583
Capital Expenditures	$	137,122	$	1,559	$	3,223				$	141,904

	For the nine months ended September 30,
	2006
($-000’s)	Electric		Gas(2)			Other		Eliminations			Total
Statement of Income Information
Revenues	$	297,566	$	6,557		$	2,113	$	(294	)	$	305,942
Operating income (loss)	55,130		(187		)	319					55,262
Income (loss) from continuing operations	33,221		(1,482		)	238					31,977
Capital Expenditures	$	85,240	$	1,593	(1)	$	2,127				$	88,960

(1)Does not include the acquisition of Missouri gas operation.

(2)Represents the months of June through September 2006.

	For the twelve months ended September 30,
	2007
($-000’s)	Electric		Gas(2)			Other			Eliminations			Total
Statement of Income Information
Revenues	$	418,255	$	60,258		$	3,513		$	(411	)	$	481,615
Operating income	67,203		4,136			925						72,264
Income (loss) from continuing operations	41,161		542			(69		)				41,634
Capital Expenditures(1)	$	168,461	$	962	(1)	$	3,726					$	173,149

(1)Does not include the acquisition of Missouri gas operation.

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	For the twelve months ended September 30,
	2006
($-000’s)	Electric		Gas			Other		Eliminations			Total
Statement of Income Information
Revenues	$	383,484	$	6,557		$	2,759	$	(383	)	$	392,417
Operating income (loss)	63,339		(187		)	389					63,541
Income (loss) from continuing operations	34,484		(1,482		)	283					33,285
Capital Expenditures(1)	$	98,772	$	1,593	(1)	$	2,770				$	103,135

(1)Does not include the acquisition of Missouri gas operation.

(2)Represents the months of June through September 2006.

	As of September 30, 2007
	Electric		Gas(1)		Other		Eliminations			Total
Balance Sheet Information
Total assets	$	1,370,604	$	118,621	$	20,621	$	(82,941	)	$	1,426,905

(1) Includes goodwill of $39,492

	As of December 31, 2006
	Electric		Gas(1)		Other		Eliminations			Total
Balance Sheet Information
Total assets	$	1,248,591	$	126,296	$	21,659	$	(80,658	)	$	1,315,888

(1) Includes goodwill of $39,323.

Note 13 – Discontinued Operations

In August 2006, we sold our controlling 52% interest in MAPP, a company that specializes 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 markets 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 September 30, follows:

	For the three months ended September 30, 2006
(in thousands)	MAPP			Conversant			Fast Freedom			Total
Revenues	$	1,904		$	575		$	333		$	2,812
Expenses	2,040			911			404			3,355
Losses from discontinued operations before income taxes	(136		)	(336		)	(71		)	(543		)
Gain on disposal	272			—			—			272
Income tax	52			128			27			207
Minority interest	65			—			—			65
Income tax – minority interest	(25		)	—			—			(25		)
Gain (loss) from discontinued operations	$	228		$	(208	)	$	(44	)	$	(24	)

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	For the nine months ended September 30, 2006
(in thousands)	MAPP			Conversant			Fast Freedom			Total
Revenues	$	8,926		$	1,513		$	1,017		$	11,456
Expenses	9,295			3,004			1,221			13,520
Losses from discontinued operations before income taxes	(369		)	(1,491		)	(204		)	(2,064		)
Gain on disposal	272			—			—			272
Income tax	140			568			78			786
Minority interest	177			—			—			177
Income tax – minority interest	(67		)	—			—			(67		)
Gain (loss) from discontinued operations	$	153		$	(923	)	$	(126	)	$	(896	)

	For the twelve months ended September 30, 2006
(in thousands)	MAPP			Conversant			Fast Freedom			Total
Revenues	$	15,209		$	2,335		$	1,334		$	18,878
Expenses	15,245			3,973			1,631			20,849
Losses from discontinued operations before income taxes	(36		)	(1,638		)	(297		)	(1,971		)
Gain on disposal	272			—			—			272
Income tax	14			624			113			751
Minority interest	17			—			—			17
Income tax – minority interest	(7		)	—			—			(7		)
Gain (loss) from discontinued operations	$	260		$	(1,014	)	$	(184	)	$	(938	)

	For the three months ended September 30, 2007
(in thousands)	MAPP	Conversant	Fast Freedom			Total
Revenues			$	282		$	282
Expenses			363			363
Losses from discontinued operations before income taxes			(81		)	(81		)
Gain on disposal			161			161
Income tax			31			31
Minority interest			—			—
Income tax – minority interest			—			—
Gain (loss) from discontinued operations			$	111		$	111

	For the nine months ended September 30, 2007
(in thousands)	MAPP	Conversant	Fast Freedom			Total
Revenues			$	905		$	905
Expenses			1,063			1,063
Losses from discontinued operations before income taxes			(158		)	(158		)
Gain on disposal			161			161
Income tax			60			60
Minority interest			—			—
Income tax – minority interest			—			—
Gain (loss) from discontinued operations			$	63		$	63

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	For the twelve months ended September 30, 2007
(in thousands)	MAPP	Conversant			Fast Freedom			Total
Revenues	$	$	308		$	1,251		$	1,559
Expenses		904			1,473			2,376
Losses from discontinued operations before income taxes		(595		)	(222		)	(817		)
Gain on disposal		555			161			717
Income tax		227			84			311
Minority interest		—			—			—
Income tax – minority interest		—			—			—
Gain (loss) from discontinued operations	$	$	187		$	24		$	211

Differences could occur due to rounding.

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 of our non-regulated businesses, primarily, a 100% interest in Empire District Industries, Inc., a subsidiary for our fiber optics business. During the twelve months ended September 30, 2007, 86.9% of our gross operating revenues were provided from sales from our electric segment (including 0.4% from the sale of water), 12.5% from the sale of gas and 0.6% from our non-regulated businesses.

In August 2006, we sold our controlling 52% interest in Mid-America Precision Products (MAPP), which specializes in close-tolerance custom manufacturing. In December 2006, we sold our 100% interest in Conversant, Inc., a software company that markets 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 1.7% over the next several years. Our electric customer growth for the

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twelve months ended September 30, 2007 was 1.2%. We define electric sales growth to be growth in kWh sales excluding the impact of weather. The primary drivers of electric sales growth are customer growth and general economic conditions.

The primary drivers of our electric operating expenses in any period are: (1) fuel and purchased power expense, (2) maintenance and repairs expense, including repairs following severe weather, (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 growth for the twelve months ended September 30, 2007 was (2.0)%, 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 third quarter of 2007, basic and diluted earnings per weighted average share of common stock were $0.76 as compared to $0.74 in the third quarter of 2006. For the nine months ended September 30, 2007, basic and diluted earnings per weighted average share of common stock were $1.11 as compared to $1.12 for the nine months ended September 30, 2006.For the twelve months ended September 30, 2007, basic and diluted earnings per weighted average share of common stock were $1.38 as compared to $1.19 for the twelve months ended September 30, 2006. As reflected in the table below, the primary positive drivers for all periods presented were increased electric and gas revenues while negative drivers for all periods presented included increased purchased power costs, natural gas sold and transported costs, regulated electric expenses, regulated gas expenses (excluding third quarter 2007), depreciation, maintenance and repairs expense (including the effect of the January 2007 ice storm costs during the nine months ended and twelve months ended periods), other taxes and interest charges. Contributing to

30

increased earnings for the twelve months ended September 30, 2007 was a decrease in electric fuel costs. However, increases in electric fuel costs negatively impacted earnings for the three and nine months ended September 30, 2007.

The following reconciliation of basic earnings per share between the three months, nine months and twelve months ended September 30, 2006 versus September 30, 2007 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 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, nine months and twelve months ended September 30, 2006 and 2007 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			Nine months Ended			Twelve Months Ended
Earnings Per Share – 2006*	$	0.74		$	1.12		$	1.19
Revenues
Electric on-system	$	0.13		$	0.62		$	0.69
Electric off – system and other	0.10			0.15			0.12
Gas**	0.02			0.81			1.26
Water	0.00			0.00			0.00
Non – Regulated	0.00			0.01			0.02
Expenses
Electric fuel	(0.07		)	(0.16		)	0.11
Purchased power	(0.01		)	(0.15		)	(0.17		)
Cost of natural gas**	(0.01		)	(0.53		)	(0.83		)
Regulated – electric	(0.05		)	(0.13		)	(0.17		)
Regulated –gas	0.01			(0.10		)	(0.17		)
Non-regulated	0.00			0.00			(0.01		)
Maintenance and repairs	(0.02		)	(0.17		)	(0.20		)
Depreciation and amortization	(0.08		)	(0.25		)	(0.27		)
Other taxes	(0.02		)	(0.09		)	(0.11		)
Loss on plant allowance	0.00			0.00			(0.02		)
Change in effective income tax rates	0.03			0.06			0.06
Interest charges	(0.03		)	(0.10		)	(0.14		)
AFUDC	0.02			0.08			0.13
Discontinued operations	0.00			0.03			0.04
Other income and deductions	0.00			0.00			(0.01		)
Dilutive effect of additional shares issued in July 2006	0.00			(0.09		)	(0.14		)
Earnings Per Share – 2007*	$	0.76		$	1.11		$	1.38

* The effects of discontinued operations for 2007 were de minimus gains for both the three months ended and the nine months ended and a gain of $0.01 for the twelve months ended September 30, 2007. The effect for 2006 was a de minimus loss for the three months ended and losses of $0.03 for both the nine months ended and twelve months ended September 30, 2006.

** Gas segment revenues and expenses began June 1, 2006.

Recent Activities

Non-Regulated Businesses

On September 28, 2007, we sold our 100% interest in Fast Freedom, Inc., an Internet service provider. For financial reporting purposes, this business has been classified as a discontinued operation and is not included in our segment information. Our gain on the disposal of Fast Freedom was $0.2 million.

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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%. This request is to allow us to recover 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 2007 ice storm and other changes in our underlying costs. We are also requesting implementation of a fuel adjustment clause in Missouri which would permit the distribution to Missouri customers of changes in fuel and purchased power costs.

On December 29, 2006, the Office of Public Counsel (OPC) and intervenors Praxair, Inc. and Explorer Pipeline Company, filed an application with the MPSC requesting the MPSC grant a rehearing on most of the issues addressed in the December 2006 Missouri rate case order and many of the procedural issues. On December 29, 2006, we also filed an application with the MPSC requesting a rehearing on return on equity, capital structure and energy cost recovery. A decision by the MPSC is pending.

Praxair and Explorer Pipeline filed a Petition for Writ of Review with the Cole County Circuit Court on January 31, 2007. The Circuit Court issued a Writ, but the MPSC has moved to have the Writ set aside and the case dismissed. The MPSC’s motion to set aside the Writ is still pending. On March 20, 2007, Praxair and Explorer filed a motion in the Circuit Court writ proceeding requesting an immediate stay of the effectiveness of our December 2006 Missouri rate case order and the tariffs filed pursuant thereto. The stay motion remains pending before the Circuit Court.

On January 4, 2007, the OPC filed a Petition for Writ of Mandamus with the Missouri Court of Appeals, Western District, seeking to have the order approving tariffs issued by the MPSC on December 29, 2006, set aside. On March 12, 2007, the Court of Appeals issued an order denying the OPC’s petition.

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 May 1, 2007, the Missouri Supreme Court issued a preliminary writ directing the MPSC to respond to the OPC’s petition. Following briefs and oral argument, on October 30, 2007, the Supreme Court made its preliminary writ peremptory and issued an opinion directing the MPSC to vacate its December 29 order approving tariffs and allow the Public Counsel 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 of the order. The Court also did not consider the underlying tariffed rates which continue in force and in effect.

Motions for rehearing may be filed with the Missouri Supreme Court within 15 days of the issuance of the opinion. In the absence of a rehearing, a mandate will be issued by the Missouri Supreme Court in mid-November, and the MPSC should thereafter take action in compliance with the writ and opinion.

For additional information, see “Rate Matters” below.

Energy Supply

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 100-megawatt Phase 1 Meridian Way Wind Farm located in Cloud County, Kansas and owned by Cloud County Windfarm, LLC. We do not own any portion of the windfarm. Annual payments are contingent

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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.

As of April 10, 2007, our new Siemens V84.3A2 combustion turbine, Unit 12 at our Riverton plant, began commercial operation. Riverton Unit 12 has a summer rated capacity of 150 megawatts, increasing our Riverton Plant’s total generating capacity to 286 megawatts.

New Union Agreement

At April 30, 2007, we had 702 full-time employees, including 54 employees of EDG, who joined us in conjunction with the gas acquisition in June 2006. 326 of the EDE employees are members of Local 1474 of The International Brotherhood of Electrical Workers (IBEW), while 26 of the EDG employees are members of Local 814 of the IBEW and 9 are members of Local 695 of the IBEW. On May 9, 2007, the Local 1474 IBEW voted to ratify a new five-year agreement effective retroactively to November 1, 2006, the expiration date of the last contract.

Financing

On March 26, 2007, EDE issued $80 million principal amount of First Mortgage Bonds, 5.875% Series due 2037. The net proceeds of $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 as a result of our on-going construction program.

BPU Contract

In May 2007, we entered into a contract with Kansas City Kansas 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.

2007 Ice Storm

A major ice storm struck virtually all areas of our electric service territory January 12-14, 2007 causing substantial damage. Approximately 85,000 (52%) of our electric customers were without power at the height of the storm. Costs associated with the restoration effort due to the ice storm were approximately $30.7 million, of which $19.2 million has been capitalized as additions to our utility plant, approximately $4.6 million recorded as maintenance expense and approximately $6.9 million was deferred as a regulatory asset as we believe it is probable that these costs will be recoverable in future electric rate cases.

Asbury SCR

In order to help meet anticipated CAIR requirements, we are constructing an SCR at Asbury. We expect the SCR to be in service by January of 2008. We have awarded a contract and the SCR is under construction and is currently being tied into the existing unit during our major turbine inspection outage in progress at the Asbury plant. Our Asbury units went off-line September 21, 2007 and are expected to be back on-line during the last week of November. As of September 30, 2007, we have spent $27.8 million (including AFUDC) on the SCR at Asbury, which is also included in our current capital expenditures budget. This project was also included as part of our Experimental Regulatory Plan approved by the MPSC. In addition, as a result of the extended outage at Asbury during the fourth quarter of 2007, we expect that our earnings for the fourth quarter will be negatively impacted compared to earnings in the fourth quarter of 2006. We will have to replace the energy generated by Asbury with energy generated at our gas plants or by buying purchased power. We estimate that this will increase our expenses approximately $7-9 million in the fourth quarter compared to the fourth quarter of 2006.

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RESULTS OF OPERATIONS

The following discussion analyzes significant changes in the results of operations for the three-month, nine-month and twelve-month periods ended September 30, 2007, compared to the same periods ended September 30, 2006.

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

	Three Months Ended						Nine months Ended					Twelve Months Ended
(in millions)	2007			2006			2007		2006			2007			2006
Income from continuing operations Electric	$	24.0		$	23.4		$	33.5	$	33.2		$	41.2		$	34.5
Gas	(0.9		)	(1.1		)	0.0		(1.4		)	0.5			(1.5		)
Other	0.1			0.1			0.1		0.2			(0.1		)	0.3
Income from continuing operations	$	23.2		$	22.4		$	33.6	$	32.0		$	41.6		$	33.3
Income/(loss) from discontinued operations	0.1			0.0			0.1		(0.9		)	0.2			(0.9		)
Net income	$	23.3		$	22.4		$	33.6	$	31.1		$	41.8		$	32.3

Differences could occur due to rounding.

Electric Segment

Overview

Our electric segment income from continuing operations for the third quarter of 2007 was $24.0 million as compared to $23.4 million for the third quarter of 2006.

Electric segment operating revenues comprised approximately 95.4% of our total operating revenues during the third quarter of 2007. Of our total electric operating revenues during the third quarter of 2007, approximately 41.2% were from residential customers, 30.4% from commercial customers, 15.2% from industrial customers, 3.9% from wholesale on-system customers, 6.1% from wholesale off-system transactions and 3.2% from miscellaneous sources, primarily public authorities. The breakdown of our customer classes has not significantly changed from the third quarter of 2006.

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 September 30, were as follows:

kWh Sales (in millions)

	3 Months Ended	3 Months Ended	%		9 Months Ended	9 Months Ended	%		12 Months Ended	12 Months Ended	%
	2007	2006	Change*		2007	2006	Change*		2007	2006	Change*
Residential	567.9	589.6	(3.7	)%	1,491.8	1,456.0	2.5	%	1,934.7	1,897.4	2.0	%
Commercial	459.4	470.5	(2.4	)	1,215.5	1,172.8	3.6		1,589.8	1,541.2	3.2
Industrial	298.3	314.7	(5.2	)	843.1	869.6	(3.0	)	1,119.1	1,147.0	(2.4	)
Wholesale On-System	98.2	96.9	1.3		260.9	258.3	1.0		340.3	336.6	1.1
Other**	30.7	31.5	(2.4	)	86.4	84.5	2.1		114.5	113.6	0.8
Total On-System	1,454.5	1,503.2	(3.2	)	3,897.7	3,841.2	1.5		5,098.4	5,035.8	1.2

Operating Revenues ($ in millions)

	3 Months		3 Months				9 Months		9 Months				12 Months		12 Months
	Ended		Ended		%		Ended		Ended		%		Ended		Ended		%
	2007		2006		Change*		2007		2006		Change*		2007		2006		Change*
Residential	$	55.9	$	52.9	5.7	%	$	136.8	$	123.7	10.6	%	$	172.5	$	158.1	9.1	%
Commercial	41.2		38.9		6.2		99.5		88.5		12.5		126.1		113.9		10.7
Industrial	20.5		20.0		2.5		52.5		50.2		4.4		67.0		64.6		3.9
Wholesale On-System	5.2		5.2		0.8		13.8		13.8		0.2		17.6		18.0		(2.6	)
Other**	3.0		2.7		9.0		7.5		6.8		10.7		9.7		9.0		8.1
Total On-System	$	125.8	$	119.7	5.2		$	310.1	$	283.0	9.6		$	392.9	$	363.6	8.1

*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.

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Quarter Ended September 30, 2007 Compared to Quarter Ended September 30, 2006

Operating Revenues and Kilowatt-Hour Sales

KWh sales for our on-system customers decreased during the third quarter of 2007 as compared to the third quarter of 2006 when we had a one time revision to our estimate of unbilled revenues and corresponding KWhs. Revenues for our on-system customers increased approximately $6.2 million, or 5.2%. The January 2007 Missouri rate increase (discussed below) contributed an estimated $9.9 million to revenues while continued sales growth contributed an estimated $2.2 million during the third quarter of 2007, partially offset by the $5.9 million revision to our estimate of unbilled revenues in the third quarter of 2006. Weather and other related factors had a negligible effect. We expect our annual electric customer growth to range from approximately 1.4% to 1.7% over the next several years. Our electric customer growth for the twelve months ended September 30, 2007 was 1.2%.

The decrease in residential, commercial and industrial kWh sales during the third quarter of 2007 as compared to the same period in 2006 was primarily due to the revision to our estimate of unbilled revenues and corresponding KWhs in the third quarter of 2006. Revenues were positively affected by the January 2007 Missouri rate increase.

On-system wholesale kWh sales increased during the third quarter of 2007 reflecting continued sales growth. Revenues associated with these FERC-regulated sales increased only slightly, 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. The following table sets forth information regarding these sales and related expenses for the applicable periods ended September 30:

	2007		2006
	Three Months		Three Months
(in millions)	Ended		Ended
Revenues	$	8.8	$	4.4
Expenses	6.1		3.2
Net*	$	2.8	$	1.2

*Differences could occur due to rounding.

Revenues less expenses increased during the third quarter of 2007 as compared to the third quarter of 2006 primarily due to sales facilitated by the SPP Energy Imbalance Services (EIS) market that began on February 1, 2007. Sales from this market contributed $3.2 million to our off-system electric revenues during the third quarter of 2007 with $2.2 million of related expense while sales from the BPU contract contributed approximately $1.8 million to revenues. Total purchase power related expenses are included in our discussion of purchased power costs below.

Operating Revenue Deductions

During the third quarter of 2007, total electric segment operating expenses increased approximately $9.7 million (10.3%) compared with the same period last year. Total fuel costs increased approximately $3.2 million (9.5%) while purchased power costs increased approximately

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$0.7 million (4.6%) during the third quarter of 2007. The increase in fuel costs was primarily due to increased generation by our gas fired units (an estimated $5.1 million) partially offset by lower prices for both the hedged and unhedged natural gas that we burned in our gas-fired units in the third quarter of 2007 (an estimated $1.2 million). Decreased coal costs reduced fuel costs approximately $0.3 million in the third quarter of 2007 while decreased coal generation reduced fuel costs approximately $0.2 million. The net increase in fuel and purchased power during the third quarter of 2007 as compared to the same period last year was $3.9 million (8.0%).

Regulated – other operating expenses for our electric segment increased approximately $2.1 million (15.6%) during the third quarter of 2007 as compared to the same period in 2006 primarily due to a $0.5 million increase in transmission and distribution expense, $0.4 million increase in employee pension expense, a $0.4 million increase in professional services, a $0.2 million increase in uncollectible accounts, a $0.2 million increase in customer accounts expense, a $0.1 million increase in labor and other costs, a $0.1 million increase in injuries and damages expense, a $0.1 million increase in regulatory commission expense and a $0.1 million increase in employee health care expense. The increase in pension costs is primarily due to the effects of regulatory accounting. We defer or record pension and other postretirement benefit costs (other than EDG other postretirement benefit costs) if they are more or less, respectively, than those allowed in rates for the Missouri and Kansas portion of pension costs. The increase in employee health care costs resulted from higher active employee costs.

Maintenance and repairs expense increased approximately $0.9 million (16.2%) as compared to the third quarter of 2006 primarily due to a $1.0 million increase in transmission and distribution maintenance costs and a $0.3 million increase at the Energy Center plant due to a bearing failure in Unit #3 in the second quarter of 2007 that was repaired in the third quarter of 2007. These increases were partially offset by a $0.2 million decrease in maintenance and repairs expense at the State Line Combined Cycle (SLCC) plant and a $0.1 million decrease in maintenance and repairs expense at the State Line plant as compared to the third quarter of 2006.

Depreciation and amortization expense increased approximately $3.5 million (37.7%) during the quarter mainly due to $2.6 million of regulatory amortization related to the January 2007 Missouri rate order that has been recorded as depreciation expense. Other taxes increased approximately $0.4 million during the third quarter of 2007 due to increased property tax reflecting our additions to plant in service and increased municipal franchise taxes.

Nine months Ended September 30, 2007 Compared to Nine months Ended September 30, 2006

Operating Revenues and Kilowatt-Hour Sales

KWh sales for our on-system customers increased during the nine months ended September 30, 2007 as compared to the nine months ended September 30, 2006 primarily due to continued sales growth and colder weather in the first quarter of 2007 as compared to 2006. Revenues for our on-system customers increased approximately $27.1 million, or 9.6%. The January 2007 Missouri rate increase (discussed below) contributed an estimated $22.1 million to revenues while continued sales growth contributed an estimated $7.5 million during the nine months ended September 30, 2007. Weather and other related factors increased revenues by approximately $3.5 million compared to the nine months ended September 30, 2006. These increases were partially offset by the $5.9 million revision to our estimate of unbilled revenues in the third quarter of 2006.

The increase in residential and commercial kWh sales during the nine months ended September 30, 2007 was primarily due to continued sales growth and the colder weather conditions in the first quarter as compared with 2006. Revenues were primarily affected by the January 2007 Missouri rate increase, as well as the continued sales growth and colder weather.

Industrial kWh sales decreased for the nine months ended September 30, 2007 as compared to the same period in 2006 primarily due to a pipeline customer running at minimum output during the first quarter of 2007 as well as the revision to our estimate of unbilled revenues

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in the third quarter of 2006. Industrial revenues increased during this period, reflecting the Missouri rate increase.

On-system wholesale kWh sales increased during the nine months ended September 30, 2007 reflecting the continued sales growth discussed above. Revenues associated with these FERC-regulated sales increased only slightly, 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 September 30:

	2007		2006
	Nine months		Nine months
(in millions)	Ended		Ended
Revenues	$	17.4	$	11.4
Expenses	12.1		8.1
Net*	$	5.3	$	3.3

*Differences could occur due to rounding.

Revenues less expenses increased during the nine months ended September 30, 2007 as compared to the nine months ended September 30, 2006 primarily due to sales facilitated by the EIS market that began on February 1, 2007. Sales from this market contributed $6.5 million to our off-system electric revenues in the nine months ended September 30, 2007 with $4.4 million of related expense while sales from the BPU contract contributed approximately $2.1 million to revenues. Total purchase power related expenses are included in our discussion of purchased power costs below.

Operating Revenue Deductions

During the nine months ended September 30, 2007, total electric segment operating expenses increased approximately $34.5 million (14.2%) compared with the same period last year. Total fuel costs increased approximately $6.9 million (9.0%) while purchased power costs increased approximately $6.5 million (13.2%) during the nine months ended September 30, 2007. The increase in purchased power costs primarily reflected increased purchases on the spot market for replacement energy due to an unscheduled outage at the Iatan plant in May 2007. The increase in fuel costs was primarily due to increased generation by our gas fired units during the nine months ended September 30, 2007 (an estimated $9.7 million) partially offset by lower prices for both the hedged and unhedged natural gas that we burned in our gas-fired units (an estimated $2.2 million). Increased coal costs contributed approximately $1.2 million to total fuel costs during the nine months ended September 30, 2007 offset by decreased coal generation (approximately $2.0 million). The net increase in fuel and purchased power during the nine months ended September 30, 2007 as compared to the same period last year was $13.4 million (10.6%).

Regulated – other operating expenses for our electric segment increased approximately $5.6 million (14.1%) during the nine months ended September 30, 2007 as compared to the same period in 2006 primarily due to a $1.7 million increase in employee pension expense, a $0.9 million increase in transmission and distribution expense, a $0.8 million increase in uncollectible accounts, a $0.5 million increase in labor and other costs, a $0.4 million increase in injuries and damages expense, a $0.4 million increase in customer accounts expense, a $0.3 million increase in professional services, a $0.3 million increase in regulatory commission expense and a $0.2 million increase in employee health care expense. We defer or record pension and other postretirement

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benefit costs (other than EDG other postretirement benefit costs) if they are more or less, respectively, than those allowed in rates for the Missouri and Kansas portion of pension costs.

Maintenance and repairs expense increased approximately $6.8 million (43.6%) as compared to the nine months ended September 30, 2006 primarily due to a $7.0 million increase in transmission and distribution maintenance costs, a $0.6 million increase in maintenance and repairs expense at the Iatan plant related to the 2007 first quarter planned maintenance and turbine inspection and a $0.4 million increase in maintenance and repairs expense at the Energy Center plant related to the Unit #3 bearing repair in the third quarter of 2007. The increase in distribution costs reflects $4.6 million related to the January 2007 ice storm. Another $1.2 million of non-incremental tree trimming and labor maintenance cost was incurred in the first quarter of 2007 due to the ice storm that otherwise would have been spent on other projects. These increases were partially offset by a $0.6 million decrease in maintenance and repairs expense at the Asbury plant as compared to 2006 when the Asbury plant had an unscheduled outage in the first quarter due to a blade failure and a $0.5 million decrease in maintenance and repairs expense for our SLCC plant.

Depreciation and amortization expense increased approximately $9.8 million (35.8%) during the nine months ended September 30, 2007 mainly due to $7.9 million of regulatory amortization related to the January 2007 Missouri rate order that has been recorded as depreciation expense. Other taxes increased approximately $1.3 million during the nine months ended September 30, 2007 due to increased property tax reflecting our additions to plant in service and increased municipal franchise taxes.

Twelve Months Ended September 30, 2007 Compared to Twelve Months Ended September 30, 2006

Operating Revenues and Kilowatt-Hour Sales

For the twelve months ended September 30, 2007, kWh sales to our on-system customers increased 1.2% with the associated revenues increasing approximately $29.3 million (8.1%). The January 2007 Missouri rate increase and January 2006 Kansas rate increase contributed an estimated $22.6 million to revenues while continued sales growth contributed an estimated $10.1 million. Weather and other related factors contributed an estimated $2.6 million. These increases were partially offset by the $5.9 million revision to our estimate of unbilled revenues in the third quarter of 2006.

Residential and commercial kWh sales and associated revenues increased primarily due to sales growth while the associated revenues also increased due to the Missouri and Kansas rate increases. Industrial kWh sales decreased for the twelve months ended September 30, 2007 as compared to the same period in 2006 primarily due to a pipeline customer running at minimum output during the first quarter of 2007 as well as the revision to our estimate of unbilled revenues in the third quarter of 2006. Industrial revenues increased during this period, reflecting the aforementioned rate increases.

On-system wholesale kWh sales increased, reflecting the sales growth discussed above, while revenues associated with these FERC-regulated sales decreased 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 September 30:

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	2007		2006
	Twelve Months		Twelve Months
(in millions)	Ended		Ended
Revenues	$	20.5	$	15.7
Expenses	14.4		11.4
Net*	$	6.0	$	4.3

*Differences could occur due to rounding.

Revenues less expenses increased during the twelve months ended September 30, 2007 as compared to the same period in 2006 primarily due to sales facilitated by the EIS market that began on February 1, 2007. Sales from this market contributed $6.5 million to our off-system electric revenues for the twelve months ended September 30, 2007 with $4.4 million of related expense while sales from the BPU contract contributed approximately $2.1 million to revenues. Total purchase power related expenses are included in our discussion of purchased power costs below.

Operating Revenue Deductions

During the twelve months ended September 30, 2007, total electric segment operating expenses increased approximately $30.9 million (9.7%) compared to the year ago period. Total fuel costs decreased approximately $4.7 million (4.5%) during the twelve months ended September 30, 2007 while purchased power costs increased $7.2 million (11.0%) during the same period. The increase in purchased power costs primarily reflected increased purchases on the spot market for replacement energy due to an unscheduled outage at the Iatan plant in May 2007 and increased purchases from the Elk River Windfarm, LLC. The decrease in fuel costs was primarily due to lower prices for both the hedged and unhedged natural gas that we burned in our gas-fired units (an estimated $6.9 million) partially offset by increased generation by our gas-fired units (an estimated $1.7 million). Decreased coal generation of approximately $1.5 million also contributed to the decrease in fuel costs, offset by increased coal costs of approximately $1.8 million. The net increase in fuel and purchased power during the twelve months ended September 30, 2007 as compared to the same period last year was $2.5 million (1.5%).

Regulated – other operating expenses increased approximately $7.1 million (13.4%) during the twelve months ended September 30, 2007 as compared to the same period last year primarily due to a $2.4 million increase in employee pension expense, a $1.2 million increase in transmission and distribution expense, a $0.9 million increase in uncollectible accounts, a $0.7 million increase in labor and other costs, a $0.7 million increase in customer accounts expense, a $0.6 million increase in professional services, a $0.4 million increase in injuries and damages expense, a $0.3 million increase in regulatory commission expense and a $0.2 million increase in employee health care expense.

Maintenance and repairs expense increased approximately $7.5 million (35.2%) during the twelve months ended September 30, 2007, compared to the year ago period reflecting increases of approximately $7.7 million in distribution maintenance costs, including $4.6 million of incremental costs (and the $1.2 million non-incremental tree trimming and labor costs in the first quarter of 2007) related to the January 2007 ice storm, a $0.6 million increase in maintenance and repairs expense at the Iatan plant related to the 2007 first quarter inspection, a $0.4 million increase in maintenance and repairs expense at the Energy Center plant related to the Unit #3 bearing repair in the third quarter of 2007 and a $0.2 million increase in maintenance and repairs at our State Line Unit 1 plant, which had its first major inspection from September 7, 2006 until December 20, 2006. These increases were partially offset by a $0.9 million decrease in maintenance and repairs expense at the Asbury plant during the twelve months ended September 30, 2007 as compared to the same period in 2006 when the Asbury plant had an unscheduled outage due to a blade failure and a $0.6 million decrease in maintenance and repairs expense at our Riverton plant.

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Depreciation and amortization expense increased approximately $10.1 million (28.0%) mainly due to $7.9 million of regulatory amortization related to the January 2007 Missouri rate order that has been recorded as depreciation expense as well as increased plant in service. Other taxes increased approximately $1.6 million due to increased property taxes reflecting our additions to plant in service and increased municipal franchise taxes.

Gas Segment

Operating Revenues and Sales

During the third quarter of 2007, our total natural gas revenues were $5.6 million as compared to $4.9 million in the third quarter of 2006. Our total natural gas revenues for the nine months and twelve months ended September 30, 2007 were approximately $41.7 million and $60.3 million, respectively. The winter months are high sales months for the natural gas business, whose heating season runs from November to March of each year.

The following table details our natural gas sales and revenues for the periods ended September 30:

Total gas delivered to customers - bcf Sales*

	2007
	Three Months Ended	Nine months Ended	Twelve Months Ended
Residential	0.14	1.87	2.77
Commercial	0.12	0.89	1.28
Industrial	0.00	0.03	0.06
Public authorities	0.00	0.02	0.03
Total retail sales*	0.27	2.81	4.14
Transportation sales	.86	3.13	4.28
Total gas operating sales*	1.13	5.94	8.42

*Differences could occur due to rounding.

	2006
	Three Months Ended	Nine months Ended**	Twelve Months Ended**
Residential	0.15	0.20	0.20
Commercial	0.13	0.17	0.17
Industrial	0.00	0.00	0.00
Public authorities	0.00	0.00	0.00
Total retail sales*	0.28	0.37	0.37
Transportation sales	.80	1.08	1.08
Total gas operating sales*	1.08	1.45	1.45

*Differences could occur due to rounding.

**2006 nine months ended and twelve months ended sales represent the months of June through September 2006.

Operating Revenues ($ in millions)*

	2007
	Three Months Ended			Nine months Ended			Twelve Months Ended
Residential	$	3.2		$	27.2		$	39.5
Commercial	1.8			11.7			16.7
Industrial	0.1			0.4			0.7
Public authorities	0.0			0.2			0.3
Total retail sales revenues	$		5.1	$		39.5	$		57.2
Transportation revenues	0.5			2.0			2.8
Total gas operating revenues	$		5.6	$		41.5	$		60.0

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

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Operating Revenues ($ in millions)*

	2006
	Three Months Ended		Nine months Ended**		Twelve Months Ended**
Residential	$	2.7	$	3.6	$	3.6
Commercial	1.7		2.2		2.2
Industrial	0.0		0.1		0.1
Public authorities	0.0		0.0		0.0
Total retail sales revenues	$	4.4	$	5.9	$	5.9
Transportation revenues	0.5		0.6		0.6
Total gas operating revenues	$	4.9	$	6.5	$	6.5

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

**2006 nine months ended and twelve months ended revenues represent the months of June through September 2006.

Operating Revenue Deductions

During the third quarter of 2007, EDG’s cost of natural gas sold and transported was approximately $2.6 million as compared to $2.2 million in the third quarter of 2006. EDG’s cost of natural gas sold and transported for the nine months and twelve months ended September 30, 2007 were approximately $26.1 million and $38.4 million, respectively. The cost of natural gas tends to vary with changing sales requirements and unit cost of natural gas purchases. However, due to purchased natural gas cost recovery mechanisms for retail customers, fluctuations in the cost of natural gas have little effect on income. Our Purchased Gas Adjustment (PGA) Clause allows us to recover from our customers, subject to routine regulatory review, the cost of purchased gas supplies, including costs, cost 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 $2.1 million for the third quarter of 2007 as compared to $2.4 million in the third quarter of 2006. Total other operating expenses were $7.6 million for the nine months ended September 30, 2007 and $10.3 million for the twelve months ended September 30, 2007. EDG had a net loss of $0.9 million for the third quarter of 2007 as compared to a net loss of $1.1 million in the third quarter of 2006. EDG had net income of $0.02 million for the nine months ended and $0.5 million for the twelve months ended periods. Approximately $1.2 million in transition costs were paid to Aquila, Inc. in 2006 for billing and other transition services. These Aquila, Inc. services ended when they were transitioned to Empire 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 remaining non-regulated businesses for the applicable periods ended September 30,:

	Three Months Ended				Nine months Ended				Twelve Months Ended
(in millions)	2007		2006		2007		2006		2007			2006
Revenues	$	1.0	$	0.7	$	2.7	$	2.1	$	3.5		$	2.8
Expenses	0.9		0.7		2.6		1.9		3.6			2.5
Net income (loss) from continuing operations*	$	0.1	$	0.1	$	0.1	$	0.2	$	(0.1	)	$	0.3

*Differences could occur due to rounding.

Consolidated Company

Income Taxes

Our consolidated provision for income taxes decreased approximately $0.8 million during the third quarter of 2007 as compared to the same period in 2006 despite higher income, primarily resulting from a lower effective tax rate. Our consolidated effective federal and state income tax rate for the third quarter of 2007 was 33.1% as compared to 35.7% for the third quarter of 2006.

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An increase in equity AFUDC, a non-taxable benefit, primarily caused the reduction to our effective tax rate for the third quarter of 2007.

Our consolidated provision for income taxes decreased approximately $1.6 million during the nine months ended September 30, 2007 as compared to the same period in 2006 as a result of our reduced effective tax rate despite higher income for the 2007 period. Our consolidated effective federal and state income tax rate for the nine months ended September 30, 2007 was 32.1% as compared to 35.5% for the same period in 2006. The reduced effective rate was primarily caused by an increase in equity AFUDC and Medicare Part D tax benefits.

Our consolidated provision for income taxes increased approximately $2.2 million during the twelve months ended September 30, 2007 as compared to twelve months ended September 30, 2006 due to higher income, partially offset by lower tax rates. Our effective federal and state income tax rate for the twelve months ended September 30, 2007 was 32.7% as compared to 35.4% for the same period in 2006 also primarily due to the increase in equity AFUDC and Medicare Part D benefits.

Nonoperating Items

Total allowance for funds used during construction (AFUDC) for both equity and borrowed funds, increased $0.9 million in the third quarter of 2007 as compared to 2006. AFUDC increased $3.5 million during the nine months ended September 30, 2007 and increased $5.5 million during the twelve months ended September 30, 2007 as compared to the same periods in 2006 due to higher levels of construction in each period.

Total interest charges on long-term debt increased $1.2 million (17.2%) in the third quarter of 2007, $4.0 million (20.9%) for the nine months ended September 30, 2007 and $4.9 million ($19.7%) for the twelve months ended September 30, 2007 as compared to the prior year periods (offset by the increased AFUDC discussed above). These increases reflect interest on the $80 million principal amount of first mortgage bonds issued March 26, 2007 by EDE, the proceeds of which were added to our general funds and used to pay down short-term indebtedness incurred as a result of our on-going construction program. The increased interest for the nine month ended and twelve month ended periods also reflect interest on the first mortgage bonds issued June 1, 2006 by EDG to fund a portion of our acquisition of the Missouri natural gas distribution operations from Aquila, Inc.

Short-term debt interest increased $0.4 million in the third quarter of 2007, $0.5 million for the nine months ended September 30, 2007 and $1.0 million for the twelve months ended September 30, 2007 as compared to the prior year periods, reflecting increased usage of short-term debt in each of those periods.

Earnings from discontinued operations, which included operations and gains recognized from the sales of MAPP, Conversant and Fast Freedom, were approximately $0.1 million for the quarter ended September 30, 2007, $0.1 million for the nine months ended September 30, 2007 and $0.2 million for the twelve months ended September 30, 2007, compared to losses of $0.02 million for the quarter ended September 30, 2006, $0.9 million for the nine months ended September 30, 2006 and $0.9 million for the twelve months ended September 30, 2006.

Other Comprehensive Income

The change in the fair value of the effective portion of our open gas contracts for our electric business 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.

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The following table sets forth the pre-tax activity 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 September 30:

	Three Months Ended						Nine Months Ended						Twelve Months Ended
(in millions)	2007			2006			2007			2006			2007			2006
Natural gas contracts settled (1)	$	(1.2	)	$	(0.5	)	$	(1.2	)	$	(1.3	)	$	(1.3	)	$	(2.0	)
Total contracts settled	$	(1.2	)	$	(0.5	)	$	(1.2	)	$	(1.3	)	$	(1.3	)	$	(2.0	)
Change in FMV of open contracts for natural gas	$	(7.1	)	$	(4.3	)	$	1.5		$	(12.6	)	$	0.7		$	(16.8	)
Total change in FMV of open contracts	$	(7.1	)	$	(4.3	)	$	1.5		$	(12.6	)	$	0.7		$	(16.8	)
Taxes	$	3.2		$	1.8		$	(0.1	)	$	5.3		$	0.2		$	7.1
Total change in OCI – net of tax	$	(5.1	)	$	(3.0	)	$	0.2		$	(8.6	)	$	(0.4	)	$	(11.7	)

(1) Reflected in fuel expense

Our average cost for our open financial natural gas hedges increased from $5.399/Dth at June 30, 2007 to $5.494/Dth at September 30, 2007.

As of June 30, 2007, we elected to change our valuation of natural gas derivatives (financial hedges) for financial reporting purposes to a new methodology which is more closely related to an independent market valuation. For accounting purposes, this change is considered a change in estimate. To reflect the change, an increase of approximately $6 million was recorded to the fair value of derivatives and $3.7 million, net of tax, was recorded to other comprehensive income at June 30, 2007. This change had no impact on the income statement.

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 October 1, 2005:

		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 - Water	June 24, 2005	469,000	35.90%	February 4, 2006
Kansas - Electric	April 29, 2005	2,150,000	12.67%	January 4, 2006

Missouri

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 $29,513,713, or 9.63%. We also requested transition from the Interim Energy Charge (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 $29,369,397 (including regulatory amortization), or 9.96%, with an effective date of January 1, 2007 and eliminating the IEC. Pursuant to this order, the collected IEC will not be 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. Of the increase, approximately $19 million was granted in the

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form of base rates, with the remainder of approximately $10.4 million granted as regulatory amortization 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. 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.

On December 29, 2006, the Office of Public Counsel (OPC) and intervenors Praxair, Inc. and Explorer Pipeline Company, filed an application with the MPSC requesting the MPSC grant a rehearing on most of the issues addressed in the December 2006 Missouri rate case order and many of the procedural issues. On December 29, 2006, we also filed an application with the MPSC requesting a rehearing on return on equity, capital structure and energy cost recovery. A decision by the MPSC is pending.

Praxair and Explorer Pipeline filed a Petition for Writ of Review with the Cole County Circuit Court on January 31, 2007. The Circuit Court issued a Writ, but the MPSC has moved to have the Writ set aside and the case dismissed. The MPSC’s motion to set aside the Writ is still pending. On March 20, 2007, Praxair and Explorer filed a motion in the Circuit Court writ proceeding requesting an immediate stay of the effectiveness of the December 2006 Missouri rate case order and the tariffs filed pursuant thereto. The stay motion remains pending before the Circuit Court.

On January 4, 2007, the OPC filed a Petition for Writ of Mandamus with the Missouri Court of Appeals, Western District, seeking to have the order approving tariffs issued by the MPSC on December 29, 2006, set aside. On March 12, 2007, the Court of Appeals issued an order denying the OPC’s petition.

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 May 1, 2007, the Missouri Supreme Court issued a preliminary writ directing the MPSC to respond to the OPC’s petition. Following briefs and oral argument, on October 30, 2007, the Supreme Court made its preliminary writ peremptory and issued an opinion directing the MPSC to vacate its December 29 order approving tariffs and allow the Public Counsel 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 of the order. The Court also did not consider the underlying tariffed rates which continue in force and in effect.

Motions for rehearing may be filed with the Missouri Supreme Court within 15 days of the issuance of the opinion. In the absence of a rehearing, a mandate will be issued by the Missouri Supreme Court in mid-November, and the MPSC should thereafter take action in compliance with the writ and opinion.

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%. This request is to allow us to recover 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 2007 ice storm and other changes in our underlying costs. We are also requesting implementation of a fuel adjustment clause in Missouri which would permit the distribution to Missouri customers of changes in fuel and purchased power costs.

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Kansas

On April 29, 2005, we filed a request with the Kansas Corporation Commission (KCC) for an increase in base rates for our Kansas electric customers in the amount of $4,181,078, or 24.64%. On October 4, 2005, we and the KCC Staff filed a Motion to Approve Joint Stipulated Settlement Agreement (Agreement) with the KCC. The Agreement called for an annual increase in base rates (which includes historical fuel costs) for our Kansas electric customers of approximately $2,150,000, or 12.67%, the implementation of an Energy Cost Adjustment Clause (ECA), a fuel rider that will collect or refund fuel costs in the future that are above or below the fuel costs included in the base rates and the adoption of the same depreciation rates approved by the MPSC in our 2005 Missouri rate case. In addition, we will be allowed to change our recognition of pension costs, deferring the Kansas portion of any costs above or below the amount included in this rate case as a regulatory asset or liability. The KCC approved the Agreement on December 9, 2005 with an effective date of January 4, 2006. Pursuant to the Agreement, we were to seek KCC approval of an explicit hedging program in a separate docket by March 1, 2006. However, we requested and received an extension until April 1, 2006. We made this filing on March 30, 2006 and are awaiting a response from the KCC.

Gas Segment

On June 1, 2006, The Empire District Gas Company (EDG) 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.

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. Although our experience to date in the EIS market is limited, it appears that we have realized some modest savings to date. However, we are still unable to quantify the impact of such EIS participation on our future financial position, results of operation or cash flows at this time.

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In general, the SPP RTO EIS market is expected to provide economical real time energy for participating members within the SPP regional footprint. Imbalance energy prices will be 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 will perform 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/value of EIS market participation.

On February 16, 2007, 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 FERC’s enforcement, and (iii) to increase transparency in the rules applicable to planning and use of the transmission system. 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 is finalizing its modifications to its transmission planning processes, pursuant to Order 890. SPP plans to make such filing to FERC on December 7, 2007.

FERC Market Power Order

In April and July 2004, 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 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 could amount to approximately $0.6 million (excluding interest) covering over a thousand hourly energy sales over the past 18 months to numerous counterparties external to our system. 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 FERC’s August 15 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 June 21, 2007, FERC issued a Final Rule related to Market-Based Rates for Wholesales of Electric Energy, Capacity, and Ancillary Services by Public Utilities which directly affects our market power assessment within our service area and Request For Rehearing related to the aforementioned pending potential refund. In reaction to the Final Rule, we were required to modify our Market Based Rate Tariff in the form of a compliance filing to FERC, which was made

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on September 17, 2007. The FERC’s ruling on our compliance filing, as well as our Request For Rehearing on the refund, are pending. We are evaluating and implementing revisions to our wholesale power sales business practices in accordance with the Final Rule.

Other FERC Rulemaking

Also on June 21, 2007, 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. 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.

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 $138.7 million of cash for regulated capital expenditures during the nine months ended September 30. 2007. Our primary sources of cash flow for these expenditures during the nine months ended September 30, 2007 were $88.4 million in internally generated funds from continuing operations and $79.8 million in gross proceeds from first mortgage bonds.

Cash Provided by Operating Activities

Our net cash flows provided by continuing operating activities were $88.4 million for the first nine months of 2007 compared to $62.4 million for the same period in 2006. Net income increased $2.6 million, with another $23.5 million of positive impact from the effect of adjustments to net income to reconcile to cash flows (primarily the effect of increased depreciation and deferred taxes). A decrease in changes in accounts payable and accrued liabilities had a $17.7 million positive cash flow effect this year compared to 2006. During the nine months ended September 30, 2006, approximately $9.0 million in fuel accounts payable balances were paid. In 2007, an additional $8.2 million is owed on construction invoices over 2006. Cash flows were also positively impacted by changes in fuel, material and supplies and prepaid expenses, other current assets and deferred charges. The negative cash flow impact of $6.9 million in cash expenditures for the ice storm that have been deferred as a regulatory asset were almost totally offset by the effect of changes to our regulatory asset accounts. Cash flows were negatively impacted in 2007 by an increase in changes in accounts receivable. This resulted from a $5.2 million tax refund received in 2006, as well as an increased trade accounts receivable balance of $8.4 million for electric and $2.7 million for gas, all of which decreased cash flows in 2007 as compared to 2006. Cash flows were also negatively impacted by decreases in changes in interest and taxes accrued, as well as other liabilities and deferred assets.

Capital Requirements and Investing Activities

Our net cash flows used in investing activities of continuing operations increased $52.4 million during the nine months ended September 30,  2007 as compared to the nine months ended

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September 30, 2006 (excluding the effect of the 2006 gas operations acquisition), primarily reflecting the ice storm and construction expenditures for Plum Point Unit 1 and Iatan 2.

Our capital expenditures totaled approximately $51.3 million during the third quarter of 2007 compared to approximately $35.7 million for the same period in 2006. Our capital expenditures totaled approximately $141.9 million during the nine months ended September 30, 2007 compared to approximately $89.1 million for the same period in 2006 (excluding the effect of the 2006 gas operations acquisition). These capital expenditures include AFUDC, capital expenditures to retire assets and benefits from salvage.

A breakdown of the capital expenditures for the quarter and nine months ended September 30, 2007 is as follows:

	Capital Expenditures
	Quarter Ended		Nine months Ended
(in millions)	September 30, 2007		September 30, 2007
Distribution and transmission system additions	$	12.1	$	34.6
New Generation – Riverton combustion turbine	—		3.8
New Generation – Plum Point Energy Station	7.0		20.6
New Generation – Iatan 2	15.1		31.3
Storms*	0.4		18.2
Additions and replacements – Asbury	9.7		17.3
Additions and replacements – Riverton, Ozark Beach and State Line Combined Cycle Unit	0.1		0.5
Additions and replacements – Iatan 1	4.4		8.1
Additions and replacements – State Line Unit 1	—		0.5
Additions and replacements – Energy Center	—		0.8
Transportation	0.3		0.4
Gas segment additions and replacements	0.8		1.4
Other (including retirements and salvage -net)*	—		1.2
Subtotal	$	49.9	$	138.7
Non-regulated capital expenditures (primarily fiber optics)	1.4		3.2
TOTAL	$	51.3	$	141.9

*For the nine months ended September 30, 2007, storm costs of $17.8 million and Other of $1.4 million, which relates to the cost of removal, are specifically related to capital expenditures associated with the January 2007 ice storm.

Approximately 69% of our cash requirements for capital expenditures during the third quarter of 2007 were satisfied internally from operations (funds provided by operating activities less dividends paid). We currently expect that internally generated funds will provide less than 1% of the funds required for the remainder of our budgeted 2007 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 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 7 of “Notes to Consolidated Financial Statements (Unaudited).”

We had estimated that our 2007 capital expenditures would total approximately $171.0 million (including AFUDC). However, due to the ice storm costs capitalized as additions to our utility plant in the first six months of 2007, we now estimate our 2007 capital expenditures to be approximately $189 million.

As of April 10, 2007, our new Siemens V84.3A2 combustion turbine, Unit 12 at our Riverton plant, began commercial operation. Riverton Unit 12 has a summer rated capacity of 150 megawatts, increasing our Riverton Plant’s total generating capacity to 286 megawatts.

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Financing Activities

Financing activities from continuing operations provided $44.2 million during the nine months ended September 30, 2007 as compared to $115.5 million during the same period in 2006. Our 2007 sources include the $80 million principal amount of first mortgage bonds issued March 26, 2007. The net proceeds of $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 as a result of our on-going construction program.

We have an effective shelf registration statement with the SEC under which approximately $243.2 million of our common stock, unsecured debt securities, preference stock and first mortgage bonds remain available for issuance. Of this amount, $120 million remains available of the original $200 million approved by the MPSC as available for first mortgage bonds. We plan to use a portion of the proceeds from issuances under this shelf 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 $47.5 million as of November 1, 2007. 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 September 30, 2007, 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 September 30, 2007, however, $67.7 million of the availability thereunder was used at such date to back up our outstanding commercial paper.

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 September 30, 2007 would permit us to issue approximately $352.8 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 September 30, 2007, we had retired bonds and net property additions which would enable the issuance of at least $547.9 million principal amount of bonds if the annual interest requirements are met. As of September 30, 2007, we are in compliance with all restrictive covenants of the EDE 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 September 30, 2007, we had property additions of $2.1 million. The mortgage also contains a limitation on the issuance by EDG

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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 September 30, 2007, this test would not allow us to issue any new first mortgage bonds. The transition service costs, although expected, negatively impact the coverage ratio.

As of September 30, 2007, our corporate credit ratings and the ratings for our securities were 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	AAA	Aaa	AAA
Senior Notes	BBB	Baa2	BB+
Trust Preferred Securities	BBB-	Baa3	BB
Commercial Paper	F2	P-2	A-3
Outlook	Stable	Negative	Stable

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 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 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.

In September 2005, we entered into an agreement with Fitch Ratings to initiate coverage of us and to assign ratings to our outstanding debt securities. 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 retail revenues. Fitch reaffirmed these ratings and outlook on April 3, 2007.

CONTRACTUAL OBLIGATIONS

Set forth below is information summarizing our contractual obligations as of September 30, 2007. Not included in these amounts are expected obligations associated with our share of the Iatan 2 construction and Iatan 1 environmental construction additions for which we have not yet

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been billed. Other postretirement benefit plans are funded on an ongoing basis to match their corresponding costs, per regulatory requirements and have been estimated for 2007-2011 as noted below. Future pension funding commitments are not expected to be material over the next 5 years and have not been estimated for later years.

	Payments Due by Period (in millions)
Contractual Obligations (1)	Total		Less than 1 Year		1-3 Years		3-5 Years		More than 5 Years
Long-term debt (w/o discount)	$	492.5	$	—	$	70.0	$	—	$	422.5
Note payable to securitization trust	50.0		—		—		—		50.0
Interest on long-term debt	624.7		34.3		65.4		58.8		466.2
Short-term debt	67.7		67.7		—				—
Capital lease obligations	0.9		0.3		0.6		—		—
Operating lease obligations (2)	3.8		1.5		1.2		0.4		0.7
Electric purchase obligations (3)	356.1		84.9		100.6		52.8		117.8
Gas purchase obligations (4)	79.9		15.5		14.3		14.5		35.6
Open purchase orders	23.6		23.5		—		0.1		—
Plum Point	49.2		23.8		25.4		—		—
SPP transmission system upgrades	8.9		8.9		—		—		—
Postretirement benefit obligation funding	9.7		1.4		3.7		4.1		0.5
Other long-term liabilities (5)	4.2		0.1		0.4		0.4		3.3
Total Contractual Obligations	$	1,771.2	$	261.9	$	281.6	$	131.1	$	1,096.6

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

(2) Excludes payments under our Elk River Wind Farm and Meridian Way Wind Farm agreements, as payments are contingent upon output of the facilities. Payments under the Elk River Wind Farm agreement can run from zero up to a maximum of approximately $16.9 million per year based on a 20 year average cost and an annual output of 550,000 megawatt hours. Payments under the Meridian Way Wind Farm agreement can range from zero to a maximum of approximately $14.6 million per year based on a 20-year average cost.

(3) Includes a water usage contract for our SLCC facility, fuel and purchased power contracts and associated transportation costs, as well as purchased power for 2010 through 2015 for Plum Point.

(4) Represents fuel contracts and associated transportation costs of our gas segment.

(5) Other Long-term Liabilities primarily represents electric facilities charges owed to City Utilities of Springfield, Missouri of $11,000 per month over 30 years.

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 September 30, 2007 our retained earnings balance was $27.3 million, compared to $24.4 million as of September 30, 2006, after paying out $29.2 million in dividends during the first nine months of 2007. 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 $1.11 for the nine months ended September 30, 2007 and were $1.39 and $0.92 for the years ended December 31, 2006 and 2005, respectively. Dividends paid per share were $0.96 for the nine months ended September 30, 2007 and $1.28 for each of the years ended December 31, 2006 and 2005.

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

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thereof after August 31, 1944 (exclusive of the first quarterly dividend of $98,000 paid after said date) would exceed 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. As of September 30, 2007, our level of earned surplus did not prevent us from issuing dividends. In addition, under certain circumstances (including defaults thereunder), 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.

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, 2006 for a discussion of our critical accounting policies. There were no changes in these policies in the quarter ended September 30, 2007.

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 6 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.

If market interest rates average 1 percentage point more in 2007 than in 2006, our interest expense would increase, and income before taxes would decrease by less than $800,000. This amount has been determined by considering the impact of the hypothetical interest rates on our highest month-end commercial paper balance for 2006. 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

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procedures to manage the risks associated with these market fluctuations, including utilizing derivatives.

We satisfied 72.5% of our 2006 generation fuel supply need through coal. Approximately 85% of our 2006 coal supply was Western coal. We have contracts and have accepted binding proposals to supply fuel for our coal plants through 2010. These contracts and accepted proposals satisfy approximately 100% of our anticipated fuel requirements for 2007, 78% for 2008, 52% for 2009 and 41% of 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 October 26, 2007, 88%, or 1.3 million Dths of our anticipated volume of natural gas usage for our electric operations for the remainder of 2007 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 September 30, 2007, our natural gas expense would increase, and income before taxes would decrease by approximately $1.2 million based on our September 30, 2007 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 November 1, 2007, we had 1.8 million Dths in storage on the three pipelines that serve our customers, which was 0.08 million Dths below our 95% target. Our long-term hedge strategy for our gas segment is still in the development process. 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 September 30:

(in millions)	2007		2006
Margin deposit assets	$	7.1	$	2.2
Margin deposit liabilities	$	0.0	$	4.3

In addition, we are holding a letter of credit from a counterparty in our favor for $6.4 million as of October 31, 2007.

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

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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 October 26, 2007, gross credit exposure related to these transactions totaled $19.2 million, 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 September 30, 2007.

There have been no changes in our internal control over financial reporting that occurred during the third quarter of 2007 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, 2006.

Item 5.  Other Information.

For the twelve months ended September 30, 2007, our ratio of earnings to fixed charges was 2.62x. See Exhibit (12) hereto.

Item 6.  Exhibits.

(a)	Exhibits.
	(12) Computation of Ratio of Earnings to Fixed Charges.
	(31)(a) Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
	(31)(b) Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
	(32)(a) Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.*
	(32)(b) Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.*

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

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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

November 7, 2007

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