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, 2006 or

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

For the transition period from                              to                         .

Commission file number: 1-3368

THE EMPIRE DISTRICT ELECTRIC COMPANY

(Exact name of registrant as specified in its charter)

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

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

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

Indicate by check mark 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, 2006, 30,190,017 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
	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 periodic revision of our construction and capital expenditure plans and cost estimates;

·legislation;

·regulation, including environmental regulation (such as NOx regulation);

·competition, including the launch of the energy imbalance market;

·electric utility restructuring, including ongoing state and federal 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 gas transportation or storage agreements;

·the performance and liquidity needs of our non-regulated businesses;

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

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

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

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

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,
	2006			2005
	(000’s except per share amounts)
Operating revenues:
Electric	$	124,750		$	118,056
Natural gas	4,930			—
Water	553			399
Non-regulated	1,350			1,300
	131,583			119,755
Operating revenue deductions:
Fuel	33,780			36,754
Purchased power	14,756			12,210
Cost of natural gas sold and transported	2,222			—
Regulated — other	15,392			13,315
Non-regulated	1,489			1,527
Maintenance and repairs	5,846			4,665
Depreciation and amortization	9,981			9,157
Provision for income taxes	12,155			9,735
Other taxes	5,757			5,531
	101,378			92,894
Operating income	30,205			26,861
Other income and deductions:
Allowance for equity funds used during construction	44			62
Interest income	105			67
Provision for other income taxes	(134		)	(38		)
Other - non-operating income	4			—
Other - non-operating expense	(315		)	(301		)
	(296		)	(210		)
Interest charges:
Long-term debt — other	6,879			5,938
Note payable to securitization trust	1,063			1,063
Short-term debt	449			61
Allowance for borrowed funds used during construction	(889		)	(63		)
Other	283			150
	7,785			7,149
Income from continuing operations	22,124			19,502
Income from discontinued operations, net of tax	228			92
Net income	$	22,352		$	19,594
Weighted average number of common shares outstanding - basic	30,120			25,962
Weighted average number of common shares outstanding - diluted	30,141			26,015
Earnings from continuing operations per weighted average share of common stock— basic and diluted	$	0.73		$	0.75
Earnings from discontinued operations per weighted average share of common stock — basic and diluted	$	0.01		$	0.00
Total earnings per weighted average share of common stock — basic and diluted	$	0.74		$	0.75
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,
	2006			2005
	(000’s except per share amounts)
Operating revenues:
Electric	$	296,147		$	273,415
Natural gas	6,557			—
Water	1,407			1,084
Non-regulated	4,008			3,903
	308,119			278,402
Operating revenue deductions:
Fuel	77,443			84,592
Purchased power	48,888			36,037
Cost of natural gas sold and transported	2,958			—
Regulated — other	42,706			41,226
Non-regulated	4,656			5,001
Maintenance and repairs	16,205			15,162
Depreciation and amortization	28,922			26,033
Provision for income taxes	16,859			11,209
Other taxes	15,259			14,744
	253,896			234,004
Operating income	54,223			44,398
Other income and deductions:
Allowance for equity funds used during construction	166			111
Interest income	298			170
Provision for other income taxes	(82		)	—
Other - non-operating income	5			—
Other - non-operating expense	(757		)	(721		)
	(370		)	(440		)
Interest charges:
Long-term debt — other	19,069			17,992
Note payable to securitization trust	3,188			3,188
Short-term debt	1,701			170
Allowance for borrowed funds used during construction	(1,844		)	(150		)
Other	811			379
	22,925			21,579
Income from continuing operations	30,928			22,379
Income from discontinued operations, net of tax	153			123
Net income	$	31,081		$	22,502
Weighted average number of common shares outstanding - basic	27,628			25,851
Weighted average number of common shares outstanding - diluted	27,645			25,900
Earnings from continuing operations per weighted average share of common stock— basic and diluted	$	1.11		$	0.87
Earnings from discontinued operations per weighted average share of common stock — basic and diluted	$	0.01		$	0.00
Total earnings per weighted average share of common stock — basic and diluted	$	1.12		$	0.87
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,
	2006			2005
	(000’s except per share amounts)
Operating revenues:
Electric	$	381,700		$	341,838
Natural gas	6,557			—
Water	1,770			1,422
Non-regulated	5,681			5,163
	395,708			348,423
Operating revenue deductions:
Fuel	105,606			96,497
Purchased power	65,571			50,558
Cost of natural gas sold and transported	2,959			—
Regulated — other	55,648			55,129
Non-regulated	6,180			6,697
Maintenance and repairs	21,918			20,028
Depreciation and amortization	38,162			33,783
Provision for income taxes	17,387			12,282
Other taxes	19,921			19,287
	333,352			294,261
Operating income	62,356			54,162
Other income and deductions:
Allowance for equity funds used during construction	361			178
Interest income	469			319
Provision for other income taxes	(102		)	(235		)
Other - non-operating income	9			—
Other - non-operating expense	(992		)	(1,027		)
	(255		)	(765		)
Interest charges:
Long-term debt — other	25,008			24,115
Note payable to securitization trust	4,250			4,250
Short-term debt	1,726			171
Allowance for borrowed funds used during construction	(1,949		)	(189		)
Other	979			457
	30,014			28,804
Income from continuing operations	32,087			24,593
Income (loss) from discontinued operations, net of tax	260			(134		)
Net income	$	32,347		$	24,459
Weighted average number of common shares outstanding - basic	27,228			25,797
Weighted average number of common shares outstanding - diluted	27,244			25,844
Earnings from continuing operations per weighted average share of common stock— basic and diluted	$	1.18		$	0.95
Earnings from discontinued operations per weighted average share of common stock — basic and diluted	$	0.01		$	0.00
Total earnings per weighted average share of common stock — basic and diluted	$	1.19		$	0.95
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,
	2006			2005
	($-000’s)
Net income	$	22,352		$	19,594
Reclassification adjustments for gains included in net income or reclassified to regulatory asset or liability	(463		)	(3,356		)
Net change in fair market value of open derivative contracts for period	(4,320		)	15,572
Income taxes	1,822			(4,642		)
Net change in unrealized (loss)/gain on derivative contracts	(2,961		)	7,574
Comprehensive income	$	19,391		$	27,168

	Nine Months Ended
	September 30,
	2006			2005
	($-000’s)
Net income	$	31,081		$	22,502
Reclassification adjustments for gains included in net income or reclassified to regulatory asset or liability	(1,268		)	(2,222		)
Net change in fair market value of open derivative contracts for period	(12,693		)	31,752
Income taxes	5,319			(11,221		)
Net change in unrealized (loss)/gain on derivative contracts	(8,642		)	18,309
Comprehensive income	$	22,439		$	40,811

	Twelve Months Ended
	September 30,
	2006			2005
	($-000’s)
Net income	$	32,347		$	24,459
Reclassification adjustments for gains included in net income or reclassified to regulatory asset or liability	(2,010		)	(4,495		)
Net change in fair market value of open derivative contracts for period	(16,827		)	28,294
Income taxes	7,143			(9,044		)
Net change in unrealized (loss)/gain on derivative contracts	(11,694		)	14,755
Comprehensive income	$	20,653		$	39,214

See accompanying Notes to Consolidated Financial Statements

7

THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEET (UNAUDITED)

	September 30, 2006		December 31, 2005
	($—000’s)
Assets
Plant and property, at original cost:
Electric	$	1,284,276	$	1,253,664
Natural gas	51,223		—
Water	10,148		9,731
Non-regulated	23,810		22,806
Construction work in progress	94,566		37,495
	1,464,023		1,323,696
Accumulated depreciation and amortization	453,546		429,919
	1,010,477		893,777
Current assets:
Cash and cash equivalents	3,936		15,969
Accounts receivable - trade, net	37,355		30,622
Accrued unbilled revenues	7,543		6,502
Accounts receivable — other	8,560		17,291
Materials and supplies	25,457		23,653
Electric fuel inventory	9,734		8,109
Natural gas inventory	12,325		—
Unrealized gain in fair value of derivative contracts	4,919		7,644
Prepaid expenses	4,238		2,093
Discontinued operations	—		4,146
	114,067		116,029
Noncurrent assets and deferred charges:
Regulatory assets	65,188		55,091
Goodwill	38,227		—
Unamortized debt issuance costs	6,148		5,711
Unrealized gain in fair value of derivative contracts	12,697		23,891
Prepaid pension asset	15,492		19,167
Other	5,784		6,098
Discontinued operations	—		2,266
	143,536		112,224
Total Assets	1,268,080		1,122,030
Capitalization and Liabilities
Common stock, $1 par value, 30,090,060 and 26,084,019 shares issued and outstanding, respectively	$	30,172	$	26,084
Capital in excess of par value	405,250		329,605
Retained earnings	24,380		19,692
Accumulated other comprehensive income, net of income tax	9,389		18,030
Total common stockholders’ equity	469,191		393,411
Long-term debt:
Note payable to securitization trust	50,000		50,000
Obligations under capital lease	547		658
First mortgage bonds and secured debt	163,078		108,052
Unsecured debt	248,943		249,207
Total long-term debt	462,568		407,917
Total long-term debt and common stockholders’ equity	931,759		801,328
Current liabilities:
Accounts payable and accrued liabilities	35,453		57,426
Short-term debt and current maturities	40,976		31,208
Customer deposits	7,153		6,269
Interest accrued	8,113		3,543
Unrealized loss in fair value of derivative contracts	2,863		2,495
Taxes accrued	18,579		1,831
Provision for rate refund	782		—
Other current liabilities	941		2,341
Discontinued operations	—		2,419
	114,860		107,532
Commitments and contingencies (Note 6)
Noncurrent liabilities and deferred credits:
Regulatory liabilities	43,271		32,882
Deferred income taxes	146,522		148,386
Unamortized investment tax credits	4,059		4,501
Postretirement benefits other than pensions	8,100		7,495
Unrealized loss in fair value of derivative contracts	—		907
Other	19,509		16,022
Discontinued operations	—		2,977
	221,461		213,170
Total Capitalization and Liabilities	$	1,268,080	$	1,122,030

See accompanying Notes to Consolidated Financial Statements.

8

THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED STATEMENT OF CASH FLOWS (UNAUDITED)

	Nine Months Ended
	September 30,
	2006			2005
	($—000’s)
Cash flow from operating activities:
Net income	$	31,081		$	22,502
Adjustments to reconcile net income to cash flows from operating activities
Depreciation and amortization	32,334			29,419
Pension expense	4,108			4,809
Deferred income taxes, net	990			1,446
Investment tax credit, net	(443		)	(441		)
Allowance for equity funds used during construction	(166		)	(111		)
Stock compensation expense	1,482			1,397
Unrealized loss on derivatives	270			1,295
Gain on the sale of Mid-America Precision Products	(272		)	—
Cash flows impacted by changes, net of acquisition, in:
Accounts receivable and accrued unbilled revenues	5,602			(13,362		)
Fuel, materials and supplies	(6,357		)	3,113
Prepaid expenses and deferred charges	(6,557		)	(2,393		)
Accounts payable and accrued liabilities	(12,512		)	16,673
Customer deposits, interest and taxes accrued	21,601			19,500
Other liabilities and other deferred credits	1,165			2,572
Accumulated provision — rate refunds	(16		)	—
Net cash provided by operating activities of continuing operations	72,310			86,419
Net cash provided by operating activities of discontinued operations	992			171
Total net cash provided by operating activities	73,302			86,590
Cash flows from investing activities:
Capital expenditures — regulated	(86,835		)	(55,561		)
Acquisition of gas operations	(103,193		)	—
Capital expenditures and other investments — non-regulated	(2,179		)	(1,933		)
Proceeds from the sale of Mid-America Precision Products	1,095			—
Net cash used in investing activities of continuing operations	(191,112		)	(57,494		)
Net cash used in investing activities of discontinued operations	(322		)	(62		)
Total net cash (used) in investing activities	(191,434		)	(57,556		)
Cash flows from financing activities:
Proceeds from first mortgage bonds - gas	55,000			—
Proceeds from issuance of common stock, net of issuance costs	78,252			5,147
Net short-term borrowings (repayments)	740			(7,936		)
Proceeds from issuance of senior notes	—			40,000
Redemption of first mortgage bonds	—			(40,000		)
Dividends	(26,394		)	(24,823		)
Premium paid on extinguished debt	—			(1,162		)
Long-term debt issuance costs	(748		)	(534		)
Payment of interest rate derivative	—			(1,386		)
Discount on issuance of senior notes	—			(220		)
Other	(441		)	(186		)
Net cash provided by/(used in) financing activities of continuing operations	106,409			(31,100		)
Net cash provided by/(used in) financing activities of discontinued operations	(310		)	(260		)
Total net cash provided by/(used in) financing activities	106,099			(31,360		)
Net decrease in cash and cash equivalents	(12,033		)	(2,326		)
Cash and cash equivalents at beginning of period	15,969			12,588
Cash and cash equivalents at end of period	$	3,936		$	10,262

See accompanying Notes to Consolidated Financial Statements.

9

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

Note 1 - Summary of Significant Accounting Policies

The accompanying interim financial statements do not include all disclosures included in the annual financial statements and therefore should be read in conjunction with the financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2005.

The information furnished reflects all adjustments, consisting only of normal recurring adjustments, which are in our opinion necessary to present fairly the results for the interim periods as well as present these periods on a consistent basis with the financial statements for the fiscal year ended December 31, 2005.

Unbilled revenues represent the estimate of receivables for electric and gas services delivered, but not yet billed to customers. The electric unbilled estimates are determined based on various assumptions, such as current month electric load requirements, billing rates by customer classification and line loss factors. Changes in those assumptions can significantly affect the estimates of unbilled revenues. During the third quarter of 2006, the Company recorded a $5.9 million increase in electric unbilled revenues as a result of certain changes to the assumptions used in determining estimated unbilled revenues.

On June 1, 2006, we acquired the Missouri natural gas distribution operations of Aquila, Inc. (Missouri Gas). (See Note 3 for additional detail regarding this acquisition). Our gas segment is operated through our wholly-owned subsidiary, The Empire District Gas Company (EDG). Our consolidated financial statements now include the accounts of The Empire District Electric Company (EDE), EDG from the date of acquisition and our wholly-owned non-regulated subsidiary, EDE Holdings, Inc. and its subsidiaries. Intercompany balances and transactions have been eliminated in consolidation. (See Note 13 for additional information regarding our three segments).

The following items reflect the significant accounting policies related to our gas business if different from those of the electric business. Significant accounting policies related to our electric and non-regulated businesses are included in our Annual Report on Form 10-K for year ended December 31, 2005.

Natural Gas Inventory

Inventory of EDG natural gas in storage is valued for inventory purposes on an average unit cost basis.

Purchased Gas Adjustments (PGA)

The PGA clause allows EDG to recover from our customers, subject to routine regulatory review, the cost of purchased gas supplies. A PGA clause is included in our rates which allows for the over recovery or under recovery resulting from the operation of the regular PGA section of the PGA clause and a calculation of the Annual Purchased Gas Adjustment. This PGA clause allows us to make rate changes periodically (up to four times) throughout the year in response to weather conditions and supply demands, rather than in one possibly extreme change per year.

We calculate the PGA factor based on our best estimate of our annual gas costs and volumes purchased for resale. The calculated factor is reviewed by the MPSC staff and approved by the MPSC. PGA factor elements considered include demand reserves, storage activity, hedging contracts, revenue and refunds, prior period adjustments and transportation costs.

Pursuant to the provisions of the PGA clause, the difference between actual costs incurred and costs recovered through the application of the PGA (including costs, cost reductions and carrying costs associated with the use of financial instruments), are reflected as a deferred charge or

10

credit until the annual review of the PGA by the MPSC. Once the MPSC review process is complete, the balance is classified as a current asset or liability and recovered from or credited to customers. The balance is amortized as amounts are reflected in customer billings.

Pensions and Post-Retirement Benefits

In our agreement with the MPSC regarding the purchase of Missouri Gas by EDG, we were allowed to adopt the pension cost recovery methodology approved in our electric Missouri Rate Case effective March 27, 2005. Also, it was agreed that the effects of purchase accounting entries related to pension and other post-retirement benefits would be ignored for ratemaking purposes. These acquisition entries have been recorded as regulatory assets, as these amounts will be recovered in future rates. (See Notes 7 and 10). The regulatory asset will be reduced in an amount equal to the difference between our estimated FAS 87 costs and the costs being recovered from customers.

Note 2 - Recently Issued Accounting Standards

In December 2004, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards No. 123 (revised 2004) “Share-Based Payment” (FAS 123R). The statement requires companies to record stock compensation expense in their financial statements based on a fair value methodology beginning no later than the first annual period beginning after June 15, 2005. During 2002, we adopted FAS 148, “Accounting for Stock-Based Compensation — Transition and Disclosure — an Amendment of SFAS 123” (FAS 148) and elected to adopt the accounting provisions of FAS 123 “Accounting for Stock-Based Compensation” (FAS 123). Under FAS 123, we recognized compensation expense over the vesting period of all stock-based compensation awards issued subsequent to January 1, 2002 based upon the fair-value of the award as of the date of issuance. We adopted FAS 123R on January 1, 2006 using the modified prospective application approach. See Note 8 — “Stock-Based Awards and Programs.”

On July 13, 2006, the FASB issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109,” (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.” FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. FIN 48 is effective for us beginning January 1, 2007 but is not expected to have a material impact.

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 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. Management is currently working to assess the impact this guidance will have, if any, on accounting for assets and liabilities that are currently measured at fair value. We don’t expect the pronouncement to have a material effect on our financial statements.

On September 29, 2006, the FASB issued FASB No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans an amendment of FASB Statements No. 87, 88, 106 and 132(R)” (FAS 158). FAS 158 is intended to improve financial reporting by requiring an

11

employer to recognize the overfunded or underfunded status of a defined benefit postretirement plan (other than a multiemployer plan) as an asset or liability in its statement of financial position and to recognize changes in that funded status in the year in which the changes occur through comprehensive income of a business entity or changes in unrestricted net assets of a not-for-profit organization. FAS 158 is also intended to improve financial reporting by requiring an employer to measure the funded status of a plan as of the date of its year-end statement of financial position, with limited exceptions. FAS 158 is effective for us for the fiscal year ended December 31, 2006. We are currently working to quantify the impact this guidance will have on our financial statements in the current year. Based on the regulatory treatment of pension and OPEB recovery afforded in our jurisdictions, we have concluded that the amount of unfunded defined benefit postretirement plan obligations will likely be recorded as a regulatory asset on our balance sheet rather than as a reduction of equity.

See Note 1 under “Notes to Consolidated Financial Statements” in our Annual Report on Form 10-K for the year ended December 31, 2005 for further information regarding recently issued accounting standards.

Note 3 — 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 EDG on June 1, 2006. We expect this acquisition to help diversify our weather risk, balancing our current summer air conditioning peak with a natural gas winter heating peak. The EDG system serves approximately 48,500 customers in northwest, north central and west central Missouri. The principal utility properties consist of approximately 93 miles of transmission mains and approximately 1,088 miles of distribution mains. We provide natural gas distribution to 44 communities in northwest, north central and west central Missouri and 174 transportation customers at rates, and in accordance with tariffs, authorized by the MPSC, with earnings primarily generated by the delivery of natural gas. Due to the seasonal nature of this business, revenues and earnings are typically concentrated in the November through March period, which generally corresponds with the heating season. The largest urban area we serve is the City of Sedalia with a population of over 20,000. We operate under franchises having original terms of twenty years in virtually all of the incorporated communities. Thirty-one of the franchises have 10 years or more remaining on their term. Although our franchises contain no renewal provisions, we have obtained renewals of all our expiring gas franchises prior to the expiration dates.

The base purchase price for these properties was originally $84 million in cash, plus working capital and subject to net plant adjustments. This was increased to $85 million in February 2006 due to an amendment to the purchase agreement where Aquila, Inc. agreed to retain certain liabilities and obligations originally to have been assumed by us. This transaction was subject to the approval of the MPSC. On March 1, 2006, we, Aquila, Inc., the MPSC staff, the Office of the Public Counsel (OPC) and three intervenors filed a unanimous stipulation and agreement with the MPSC, requesting it approve the proposed transaction. On April 18, 2006, the MPSC issued an Order Approving Unanimous Stipulation and Agreement and Granting a Certificate of Public Convenience and Necessity, effective May 1, 2006. The total purchase price paid to Aquila, Inc., including working capital and net plant adjustments of $17.1 million (subject to post-closing adjustment), was $102.1 million.We recorded$38.2 million of goodwill as a result of the acquisition. This amount could be subject to change as we finalize the purchase accounting for this transaction, which is expected to occur in the fourth quarter of 2006. Goodwill represents the excess of the cost of the acquisition over the fair value of the related net assets at the date of acquisition. In accordance with Statement of

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Financial Accounting Standards No. 142, “Goodwill and Other Intangible Assets,” goodwill is required to be tested for impairment on an annual basis or whenever events or circumstances indicate possible impairment. In performing impairment tests, valuation techniques require the use of estimates with regard to discounted future cash flows of operations, involving judgments based on a broad range of information and historical results. If the test indicates impairment has occurred, goodwill would be reduced, adversely impacting earnings. We intend to perform our first required annual goodwill impairment analysis in the fourth quarter of 2006. We expect all of the goodwill to be deductible for tax purposes.

The components of the purchase price allocation for the Missouri Gas acquisition are shown below. (See Note 9 — “Financing Activities,” for information on the purchase price financing). Assets and liabilities are valued at fair value. In the case of property, plant and equipment, fair value is calculated in a manner consistent with the amount recoverable for regulatory treatment.

(In thousands)	Missouri Gas
Purchase Price:
Cash paid	$	102,126
Acquisition costs	2,082
Total	$	104,208
Allocation:
Property, plant and equipment	$	52,043
Current assets	16,081
Goodwill	38,227
Other assets	9,769
Other liabilities	(11,912		)
Total	$	104,208

The gas operations are operated through our subsidiary, The Empire District Gas Company (EDG). We contracted with Aquila, Inc. to provide transition services including billing, customer service, credit and collections, and assistance with gas supply and purchase gas adjustment filings. Virtually all of these services have been transitioned to EDG as of the end of September 2006. The cost of these services was approximately $0.4 million in June and $0.8 million for the third quarter of 2006.

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

	Three Months Ended				Nine Months Ended				Twelve Months Ended
($-000’s)	2006		2005		2006		2005		2006		2005
Revenues	$	131,583	$	123,123	$	337,764	$	315,951	$	446,983	$	403,975
Net income from continued operations	22,124		18,041		31,814		21,133		33,714		23,551
Earnings per share from continued operations:
Basic and diluted	$	0.73	$	0.69	$	1.15	$	0.82	$	1.24	$	0.91

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Note 4 — Risk Management and Derivative Financial Instruments

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

Electric Segment

As of September 30, 2006 and December 31, 2005, we have recorded the following assets and liabilities representing the fair value of qualifying derivative financial instruments held as of that date and subject to the requirements of FAS 133:

Derivative Summary

(In thousands)	September 30, 2006			December 31, 2005
Current assets	$	4,919		$	8,639
Unamortized option premiums	(850		)	—
Noncurrent assets	12,697			23,891
Current liabilities(1)	(1,598		)	(2,495		)
Noncurrent liabilities	—			(907		)
Fair market value of derivatives (before tax)	15,168			29,128
Tax effect	(5,779		)	(11,098		)
Total OCI — per Balance Sheet	$	9,389		$	18,030
(Unrealized Gain — net of tax)

(1) Excludes $1.3 million related to EDG which is not a component of OCI.

A $9.4 million net of tax, unrealized gain representing the fair market value of these derivative contracts is recognized as Accumulated Other Comprehensive Income in the capitalization section of the balance sheet as of September 30, 2006. The tax effect of $5.8 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, 2006 and ending on September 30, 2011. At the end of each determination period, any gain or loss for that period related to the instrument will be reclassified to fuel expense.

We record unrealized gains/(losses) on the overhedged portion of our gas hedging activities 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 overhedged 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)	2006		2005			2006			2005			2006			2005
Overhedged Portion	$	—	$	(1,324	)	$	(34	)	$	(820	)	$	(223	)	$	(262	)
Qualified Portion	$	463	$	3,356		$	1,268		$	3,608		$	2,010		$	5,881

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

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future executed contracts that otherwise qualify for the normal purchases exception contain a price adjustment feature and will account for these contracts accordingly.

As of October 27, 2006, 87% of our anticipated volume of natural gas usage for our electric operations for the remainder of year 2006 is hedged, either through physical or financial contracts, at an average price of $6.80 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 seven years are hedged at the following average prices per Dth:

Year	% Hedged		Dth Hedged	Average Price
2007	77	%	7,944,980	$	6.62
2008	50	%	5,300,000	$	6.65
2009	33	%	3,696,000	$	5.42
2010	34	%	3,696,000	$	5.42
2011	34	%	3,696,000	$	5.42
2012-2013	11	%	2,400,000	$	7.30

Gas Segment

On June 1, 2006, the acquisition of Missouri Gas was finalized. We hedge our natural gas price risk for EDG 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 27, 2006, we have 3.5 million Dths of natural gas, or 84%, of our expected usage hedged for the upcoming winter heating season (November 2006 through March 2007). We target to have 95% of our storage capacity full by November 1 of the upcoming winter heating season. As of October 28, 2006 we have 1.8 million Dths in storage on the three pipelines that serve our customers. This represents 91% of our storage capacity, leaving 0.1 million Dths to be injected into storage by November 1, 2006 to meet our 95% target. Our long-term hedge positions for gas are still in the development process. We have a Purchased Gas Adjustment (PGA) clause included in our rates along with an Annual Cost Adjustment (ACA) which allows for the over/under recovery of prudent natural gas costs incurred. Due to having the PGA in our rates, we mark to market any unrealized gains or losses and any realized gains or losses relating to financial derivative contracts to a regulatory asset or regulatory liability account on our balance sheet.

The bulk of physical supply to serve the EDG property comes from Mid-Continent production areas with about 10% of supply typically from Wyoming/Colorado resources.

EDG has agreements with many of the major suppliers and firm transportation to multiple production zones in the mid-continent region to provide for diverse supply. EDG continues to seek additional supplier agreements to provide for diversity and competition in meeting requirements.

Note 5 — Short-Term Borrowings

On July 15, 2005, we entered into a $150 million unsecured revolving credit facility expiring on 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 will reduce over the next four years in line with the amount of construction expenditures we owe for Plum Point and is $68.5 million as of October 1, 2006. The unallocated credit facility is used for

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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, 2006, 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, 2006, however, $40.8 million of the availability thereunder was used at such date to back up our outstanding commercial paper.

Note 6 — Commitments and Contingencies

On March 14, 2006, we entered into contracts to add 100 megawatts of power to our system. This power will come from the Plum Point Energy Station, a new 665-megawatt, coal-fired generating facility which will be built near Osceola, Arkansas. Construction began in the spring of 2006 with completion scheduled for 2010. Initially we will own an undivided interest equal to 50 megawatts of the project’s capacity for approximately $85 million in direct costs excluding AFUDC. We also have a long term purchased power agreement for an additional 50 megawatts of capacity and have the option to convert the 50 megawatts covered by the purchased power agreement into an ownership interest in 2015. We currently anticipate spending $20 million in 2006, (of which $14.9 million has been funded at September 30, 2006), $23.3 million in 2007 and $23.9 million in 2008 for construction expenses related to our 50 megawatt ownership share of Plum Point with additional expenditures in 2009 and 2010.

We entered into an agreement with Kansas City Power & Light (KCP&L) on June 13, 2006 to purchase an undivided ownership interest in the proposed coal-fired Iatan 2. We will own 12%, or approximately 100 megawatts, of the proposed 850-megawatt unit. KCP&L, which owns 54.7% of the unit, publicly reported in its 2005 10-K that it expects its share of the total construction costs to be $733 million. Over the last several months, KCP&L has finalized contracts and received bids for the largest cost components of the construction of Iatan No. 2. KCP&L recently announced that the estimated costs for Iatan No. 2 have increased due to constrained labor and material resources. KCP&L also stated that it has approximately 60% of the total estimated cost of Iatan No. 2 under firm contract as of September 30. 2006, and has started construction activities at the site. An owners’ engineer has been hired and the engineering design for Iatan Station is approximately 25% complete, which is on schedule with the targeted project completion in summer 2010.

The disclosure in KCP&L’s 2005 10-K equates to a total estimated construction budget for Iatan 2 of approximately $1.34 billion. As noted above, however, costs have increased. Although KCP&L has not stated specifically how much costs for Iatan 2 have increased, it has stated that the overall cost estimates of its comprehensive energy plan are currently expected to be about 20% above the estimate in its 2005 Form 10-K. Assuming this 20% increase applied to Iatan 2 (as the high end of the range), the total project cost would be increased to approximately $1.6 billion and our share of the Iatan 2 costs would increase from $160.8 million to approximately $190 million. We currently anticipate spending $14 million in 2006, $48 million in 2007 and $64 million in 2008 for our share of Iatan 2 with additional expenditures in 2009 and 2010. At September 30, 2006, we have spent approximately $7.5 million on this project.

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As a requirement for the air permit for Iatan 2, additional emission control equipment is required for Iatan 1. Iatan 1 environmental upgrades are on schedule with approximately 80% of the total estimated costs under firm contract as of September 30, 2006. Our estimated share of the environmental retrofit costs at Iatan 1 are estimated at $45 million and will be expended between 2006 and the end of 2008. At September 30, 2006, we have spent approximately $0.9 million on this project.

See also our discussion of pension benefits in Note 7.

Note 7 — Pension and Other Employment and Post -Employment Benefits

Based on the performance of our pension plan assets through January 1, 2005 and 2006, we were not required under the Employee Retirement Income Security Act of 1974 (ERISA) to fund any additional minimum ERISA amounts with respect to 2005 or 2006.

Missouri Gas employees became EDG employees and participants in the EDE plan on June 1, 2006. The Missouri Gas accumulated pension obligations and assets were re-measured on that date.  A discount rate of 6.30% and an expected return on assets of 7.00% were used to measure the estimated benefit obligations. The estimated impact on our pension and other post employment benefits (OPEB) unfunded status (subject to final true up) to reflect the acquisition of Missouri Gas is as follows (in thousands):

	Pension			OPEB
Benefit obligation	$	(13,442	)	$	(2,182	)
Fair value of assets	11,449			1,258
Unfunded status	$	(1,993	)	$	(924	)

These unfunded obligations were offset by regulatory assets recorded in the purchase accounting for the Missouri Gas acquisition. These regulatory assets are expected to be recovered in rates as a result of the agreed upon stipulation with the MPSC.

We expect to make OPEB contributions of $4.2 million in 2006, of which $3.7 million has been made as of September 30, 2006.

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

	Pension Benefits						OPEB
	Three months ended September 30
	2006			2005			2006			2005
Service cost	$	785		$	705		$	360		$	503
Interest cost	1,980			1,357			824			616
Expected return on plan assets	(2,507		)	(1,563		)	(725		)	(635		)
Amortization of prior service cost	135			100			(147		)	(172		)
Amortization of transition obligation	—			—			—			290
Amortization of actuarial loss	834			681			600			338
Net periodic benefit cost	$	1,227		$	1,280		$	912		$	940

	Pension Benefits						OPEB
	Nine months ended September 30
	2006			2005			2006			2005
Service cost	$	2,552		$	2,455		$	1,362		$	1,603
Interest cost	5,549			4,807			2,485			2,566
Expected return on plan assets	(6,986		)	(5,413		)	(2,080		)	(1,835		)
Amortization of prior service cost	335			350			(347		)	(472		)
Amortization of transition obligation	—			—			—			840
Amortization of actuarial loss	2,485			2,531			1,800			1,488
Net periodic benefit cost	$	3,935		$	4,730		$	3,220		$	4,190

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	Pension Benefits						OPEB
	Twelve months ended September 30
	2006			2005			2006			2005
Service cost	$	3,569		$	3,130		$	1,828		$	1,983
Interest cost	7,427			6,307			3,231			3,313
Expected return on plan assets	(9,274		)	(7,277		)	(2,613		)	(2,325		)
Amortization of prior service cost	479			465			(484		)	(624		)
Amortization of transition obligation	—			—			—			1,111
Amortization of actuarial loss	3,311			2,752			2,232			1,924
Net periodic benefit cost	$	5,512		$	5,377		$	4,438		$	5,382

We began recording a regulatory asset for deferred pension costs during the second quarter of 2005 pursuant to our March 10, 2005 Missouri rate case order. As of September 30, 2006, the deferral is approximately $2.1 million, which we expect to collect in rates in future periods. Effective January 1, 2006, we also began recognizing the difference between actual pension costs and pension costs allowed in our Kansas rates. The difference was approximately $0.1 million at September 30, 2006 and is recorded as a regulatory liability.

Note 8- Stock-Based Awards and Programs

We have several stock-based awards and programs, which are described below. Effective January 1, 2006, we adopted FAS 123(R) “Share-Based Payments” and applied it to our stock-based awards and programs using the modified prospective approach. We had previously recognized compensation expense over the vesting period of all stock-based compensation awards issued subsequent to January 1, 2002 based upon the fair value of the award as of the date of issuance. The adoption of FAS123(R) did not have a material impact on our financial results, as compared to prior periods.

We recognized the following amounts (in thousands) 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
	2006		2005		2006		2005		2006		2005
Compensation Expense	$	361	$	414	$	1,299	$	1,277	$	1,748	$	1,760
Tax Benefit Recognized	129		148		467		458		629		631

Stock Incentive Plans

Our 2006 Stock Incentive Plan (the 2006 Incentive Plan) was adopted by shareholders at the annual meeting on April 28, 2005 and provides for grants of up to 650,000 shares of common stock through January 2016. The 2006 Stock Incentive Plan permits grants of stock options and restricted stock to qualified employees and permits Directors to receive common stock in lieu of cash compensation for service as a Director. The terms of the 2006 Incentive Plan are substantially the same as the 1996 Stock Incentive Plan. Awards made prior to 2006 were made under the 1996 Stock Incentive Plan; awards made on or after January 1, 2006 are made under the 2006 Incentive Plan.

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Performance-Based Restricted Stock Awards

Beginning in 2002, performance-based restricted stock awards were granted to qualified individuals consisting of the right to receive a number of shares of common stock at the end of the restricted period assuming performance criteria are met. The performance measure for the award is the total return to our shareholders over a three-year period compared with an investor-owned utility peer group. The threshold level of performance under the 2005 and 2006 grants was set at the 20th percentile level of the peer group, target at the 50th percentile level, and maximum at the 80th percentile level. Shares would be earned at the end of the three year performance period as follows: 100% of the target number of shares if the target level of performance is reached, 50% if the threshold is reached, and 200% if the percentile ranking is at or above the maximum, with the number of shares interpolated between these levels. However, no shares would be payable if the threshold is not reached.

The fair value of these stock awards is determined based on the number of shares granted and the quoted price of our stock. Upon adoption of FAS123(R), the fair value of the estimated shares to be awarded under each grant was estimated on the date of grant using a lattice-based option valuation model with the assumptions noted in the following table:

	2006
Risk-free interest rate	4.54% to 4.60%
Expected volatility of Empire stock	15.2%
Expected volatility of peer group stock	19.8%
Expected dividend yield on Empire stock	5.80%
Expected forfeiture rates	0.3% to 1.7%
Plan cycle	3 years
EDE percentile performance	33rd
Fair value percentage (Conversion ratio of target)	51.26%

The 51.26% represents the estimate of the non-vested awards to be granted.

Non-vested restricted stock awards (based on target number) as of September 30, 2006 and changes during the nine months ended September 30, 2006 and 2005 were as follows:

	YTD 2006				YTD 2005
	Number  of shares		Weighted Average Grant Date  Fair Value		Number of shares		Weighted Average Grant Date Fair Value
Nonvested at January 1,	40,300		$	20.76	47,100		$	20.32
Granted	13,600		$	22.23	12,100		$	22.77
Awarded	(7,954	)	$	18.25	(8,815	)	$	20.95
Not Awarded	(7,146	)			(10,085	)
Nonvested at September 30,	38,800		$	22.25	40,300		$	20.76

At September  30, 2006, there was $ 0.1 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

Stock options are issued with an exercise price equal to the fair market value of the shares on the date of grant, become exercisable after three years and expire ten years after the date granted. Participants’ options that are not vested become forfeited when participants leave Empire except for terminations of employment under certain specified circumstances. Dividend equivalent awards were also issued to the recipients of the stock options under which dividend equivalents will be accumulated for the three-year period until the option becomes exercisable. For the 2002 awards (the first year options and dividend equivalents were awarded), the dividend equivalents converted to

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restricted shares of our common stock based on the fair market value of the shares on the date converted. These restricted shares would vest on the eighth anniversary of the grant date of the dividend equivalent award or, if earlier, upon exercise of the related option in full. As all the related options were exercised in 2005, the dividend equivalent restricted shares vested and were payable upon the exercise in full of the related option.

Beginning with the 2003 dividend equivalent awards, the dividend equivalents are accumulated for the three-year period and are converted to shares of our common stock based on the fair market value of the shares on the date converted. To be in compliance with Section 409A of the Internal Revenue Code added by the American Jobs Creation Act of 2004, the dividend equivalent awards were changed to vest and be payable in fully vested shares of our common stock on the third anniversary of the grant date (conversion date) or at a change in control and not dependent upon the exercise of the related option. This modification did not have a material impact on our financial statements.

A summary of option activity under the plan during the nine months ended September 30 2006 and 2005 is presented below:

	2006			2005
		Weighted Average			Weighted Average
		Exercise			Exercise
	Options	Price		Options	Price
Outstanding at December 31,	142,500	$	20.84	173,100	$	20.45
Granted	41,700	$	22.23	39,100	$	22.77
Exercised	49,200	$	18.25	69,700	$	20.95
Outstanding at September 30, 2006	135,000	22.21		142,500	20.84
Exercisable at September 30, 2006	—	—		—	—

The aggregate intrinsic value at September 30, 2006 was less than $0.1 million. The aggregate intrinsic value at September 30, 2005 was $0.3 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, 2006 was $21.79 to $22.77. The weighted-average remaining contractual life of outstanding options at September 30, 2006 and 2005 was 8.3 years and 8.3 years, respectively. The outstanding shares as of September 30, 2006 represents the non-vested shares. As of September 30, 2006, there was $0.3 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.

The fair value of the options granted, which is amortized to expense over the option vesting period, has been determined on the date of grant using the methods and assumptions outlined in the table below.

	Stock Options
				2005
Valuation Methodology	2006 Black-Scholes			Expanded Black-Scholes
Weighted average fair value of grants	$	1.65		$	4.38
Risk-free interest rate	3.27		%	3.63		%
Dividend yield (1)	6.16		%	0		%
Expected volatility	18.14		%	15.51		%
Expected life in months	60			60
Grant Date	2/1/06			2/3/05

(1)The 2005 grants were valued using an Expanded Black-Scholes method, which included a valuation component for the existence of dividend equivalents, rather than a separate assumption for the dividend equivalents issued under Black-Scholes. In 2006, dividend equivalents were separated from the evaluation.

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Employee Stock Purchase Plan

Our Employee Stock Purchase Plan (ESPP) permits the grant to eligible employees of options to purchase common stock at 90% of the lower of market value at date of grant or at date of exercise. The lookback feature of this plan is valued at 90% of the Black-Scholes methodology plus 10% of the maximum subscription price. As of September 30, 2006, there were 518,498 shares available for issuance in this plan. The adoption of FAS 123(R) did not change the valuation of the options granted under this plan.

	2006			2005
Subscriptions outstanding at September 30	39,986			41,004
Maximum subscription price	$	20.05	(1)	$	21.03
Shares of stock issued	39,322			43,133
Stock issuance price	$	19.62		$	18.00

(1) Stock will be issued on the closing date of the purchase period, which runs from June 1, 2006 to May 31, 2007.

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

	ESPP Nine months ended
	2006			2005
Valuation Methodology	Black-Scholes			Black-Scholes
Weighted average fair value of grants	$	3.19		$	3.24
Risk-free interest rate	5.02		%	3.25		%
Dividend yield	5.75		%	5.5		%
Expected volatility	18.3		%	15.38		%
Expected life in months	12			12
Grant Date	6/1/06			6/1/05

Note 9 — Financing Activities

On June 1, 2006, we used $55 million of privately placed 6.82% First Mortgage Bonds due 2036 issued by EDG to fund a portion of our acquisition of Missouri Gas from Aquila, Inc. We used short-term debt to fund the remainder of the acquisition, which was replaced with common equity on June 21, 2006.

On June 21, 2006, we sold 3,795,000 shares of our common stock, including an additional 495,000 shares to cover the underwriters’ over-allotments, in an underwritten public offering for $20.25 per share. The sale resulted in net proceeds of approximately $73.3 million ($76.8 million less issuance costs of $3.5 million). The proceeds were used to pay down short-term debt, including short-term debt used to fund a portion of our acquisition of Missouri Gas. (See Note 3 — “Acquisition of Missouri Natural Gas Distribution Operations”).

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Note 10 - Regulatory Matters

Electric Segment

All of our electric regulatory assets as of September 30, 2006 have been allowed recovery in the state of Missouri as a result of the March 10, 2005 rate case order, except for $5.0 million which primarily consists of $1.4 million in unamortized premiums and related costs for debt reacquired, $1.3 million of loss remaining from a 2005 interest rate derivative transaction and $2.1 million related to deferred Missouri pension costs. These costs were incurred subsequent to our 2004 Missouri rate case filings. Since cost recovery of debt related costs has historically been allowed in rate cases in all of our jurisdictions and the recovery of pension costs was allowed in our last rate case, we expect them to be approved in future rate case proceedings. In addition, losses and gains on our prior interest rate derivatives were included in our recently approved Missouri electric rate case. Since these items increase and reduce, respectively, our effective interest cost, we believe it is probable they will also be allowed in our other jurisdictions, as well.

We are currently collecting an Interim Energy Charge (IEC) of $0.002131 per kilowatt hour of customer usage authorized by the MPSC. This IEC is designed to recover variable fuel and purchased power costs we incur in our electric operations subject to a ceiling and floor on the amount recoverable (including realized gains or losses associated with our natural gas hedging program discussed in Note 4) which are higher than such costs included in the base rates allowed in the most recent Missouri rate case. This revenue is recorded when service is provided to the customer and subject to refund to the extent collected amounts exceed variable fuel and purchased power costs. At each balance sheet date, we evaluate the probability that we would be required to refund either a portion or all of the amounts collected under the IEC to customers. At September 30, 2006 and December 31, 2005, no provision for refund had been recorded.

Gas Segment

A PGA clause is included in our gas rates which allows for the over recovery or under recovery resulting from the operation of the regular PGA section of the PGA clause and a calculation of the Annual Purchased Gas Adjustment. This PGA clause allows us to make rate changes periodically (up to four times) throughout the year in response to weather conditions and supply demands, rather than in one possibly extreme change per year. We have a regulatory asset for the PGA of $3.6 million recorded as of September 30, 2006.

We calculate the PGA factor based on our best estimate of our annual gas costs and volumes purchased for resale. The calculated factor is reviewed by the MPSC staff and approved by the MPSC. PGA factor elements considered include demand reserves, storage activity, hedging contracts, revenue and refunds, prior period adjustments and transportation costs.

The Actual Cost Adjustment (ACA) is a scheduled yearly filing with the MPSC filed between October 15 and November 4 each year. 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 ACA filing was completed on November 3, 2006.

We also recorded a regulatory asset related to our purchase of Missouri Gas based on Accounting Authority Orders from the MPSC. These deferred costs are being amortized monthly to expense over seven years. The balance of these regulatory assets at September 30, 2006 was $0.8 million. In addition, as a result of purchase accounting, we recorded approximately $7.8 million in regulatory assets, of which $5.5 million was part of the acquisition, to reflect the future recovery of the re-valuation of our Pension and Other Post-employment Benefits related to the Missouri Gas operations. (See Note 3).

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At September 30, 2006, all our regulatory assets (electric and gas) totaled $65.2 million.

Note 11 — Accounts Receivable - Other

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

	September 30, 2006		December 31, 2005
Accounts receivable for meter loops, meter bases, line extensions, highway projects, etc.	$	2,154	$	3,570
Accounts receivable for non-regulated subsidiary companies	692		1,107
Accounts receivable — other for EDG	116		—
Accounts receivable from Westar Generating, Inc. for commonly-owned facility	499		690
Taxes receivable — overpayment of estimated income taxes	1,936		8,504
Accounts receivable for energy trading margin deposit (1)	2,186		2,104
Accounts receivable for true-up on maintenance contracts (2)	956		1,193
Other	21		123
Total accounts receivable — other	$	8,560	$	17,291

(1) The $2.2 million accounts receivable for energy trading margin deposit represents the balance in our brokerage account as of September 30, 2006. NYMEX futures contracts are used in our hedging program of natural gas which require posting of margin.

(2) The $1.0 million in accounts receivable for true-up on maintenance contracts represents $0.5 million remaining of the $2.1 million gross amount of a true-up credit from Siemens Westinghouse in September 2006 related to our maintenance contract entered into in July 2001 for the State Line Combined Cycle (SLCC) and $0.5 million of quarterly estimated credits accrued in the third quarter of 2006. Forty percent of this credit belongs to Westar Generating, Inc., the owner of 40% of the SLCC, and has been recorded in accounts payable as of September 30, 2006.

Note 12 - Regulated - Other Operating Expense

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

	3 Months Ended			3 Months Ended			9 Months Ended			9 Months Ended		12 Months Ended			12 Months Ended
	2006			2005			2006			2005		2006			2005
Electric transmission and distribution expense	$	2,052		$	2,305		$	6,040		$	6,128	$	8,036		$	8,027
Natural gas transmission and distribution expense	416			-			539			—		539			—
Power operation expense (other than fuel)	2,513			2,478			7,122			6,900		9,775			9,391
Customer accounts & assistance expense	2,184			1,759			5,869			5,196		7,639			7,106
Employee pension expense (1)	1,041			824			2,834			3,291		3,105			4,242
Employee healthcare plan	1,780			1,760			5,449			6,851		7,285			9,256
General office supplies and expense	2,073			1,705			5,790			4,909		7,672			7,201
Administrative and general expense	3,150			2,079			8,081			6,538		10,106			8,226
Allowance for uncollectible accounts	304			417			1,173			1,344		1,643			1,570
Miscellaneous expense	(121		)	(12		)	(191		)	69		(152		)	110
Total	$	15,392		$	13,315		$	42,706		$	41,226	$	55,648		$	55,129

(1) Does not include capitalized portion or amount deferred to a regulatory asset.

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Note 13 — Segment Information

We operate our businesses as three segments: electric, gas and other. The Empire District Electric Company is an operating public utility engaged in the generation, purchase, transmission, distribution and sale of electricity in parts of Missouri, Kansas, Oklahoma and Arkansas. As part of our electric segment, we also provide water service to three towns in Missouri. The Empire District Gas Company 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 44 communities in northwest, north central and west central Missouri. The other segment consists of our businesses which are unregulated and include a 100% interest in Empire District Industries, Inc., a subsidiary for our fiber optics business; a 100% interest in Conversant, Inc., a software company that markets Customer Watch, an Internet-based customer information system software, a 100% interest in Utility Intelligence, Inc., a company that distributes automated meter reading equipment and a 100% interest in Fast Freedom, Inc., an Internet provider. As discussed in “Note 14 — Discontinued Operations,” we sold our controlling 52% interest in Mid-America Precision Products (MAPP) to other current owners on August 31, 2006. MAPP is a company that specializes in close-tolerance custom manufacturing for the aerospace, electronics, telecommunications and machinery industries. We had acquired a controlling 50.01% interest in MAPP in July 2002. For financial reporting purposes, MAPP has been classified as a discontinued operation and is not included in our segment information.

Labor costs from electric employees who perform duties for the gas segment or other segment are charged to gas labor expense and other labor expense, respectively. The shared expenses are allocated among the segments as appropriate.

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

	For the quarter ended September 30,
	2006
	Electric		Gas			Other			Eliminations			Total
($-000’s)
Statement of Operations Information
Revenues	$	125,308	$	4,930		$	1,613		$	(268	)	$	131,583
Operating income (loss)	30,494		(139		)	(150		)	—			30,205
Income (loss) from continuing operations	23,418		(1,113		)	(181		)	—			22,124
Capital Expenditures	33,418		1,205			553			—			35,176

	2005
($-000’s)
Statement of Operations Information
Revenues	$	118,460	$	—	$	1,431		$	(136	)	$	119,755
Operating income (loss)	27,143		—		(282		)	—			26,861
Income (loss) from continuing operations	19,810		—		(308		)	—			19,502
Capital Expenditures	14,739		—		516			—			15,255

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	For the nine months ended September 30,
	2006
	Electric		Gas			Other			Eliminations			Total
($-000’s)
Statement of Operations Information
Revenues	$	297,566	$	6,557		$	4,577		$	(581	)	$	308,119
Operating income (loss)	55,130		(187		)	(720		)	—			54,223
Income (loss) from continuing operations	33,221		(1,482		)	(811		)	—			30,928
Capital Expenditures	85,240		1,593		(1)	2			—			86,835

	2005
	Electric		Gas		Other			Eliminations			Total
($-000’s)
Statement of Operations Information
Revenues	$	274,509	$	—	$	4,192		$	(299	)	$	278,402
Operating income (loss)	45,545		—		(1,147		)	—			44,398
Income (loss) from continuing operations	23,602		—		(1,223		)	—			22,379
Capital Expenditures	55,559		—		1,997			—			57,556

	For the twelve months ended September 30,
	2006
	Electric		Gas			Other			Eliminations			Total
($-000’s)
Statement of Operations Information
Revenues	$	383,485	$	6,557		$	6,342		$	(676	)	$	395,708
Operating income (loss)	63,339		(187		)	(796		)	—			62,356
Income (loss) from continuing operations	34,484		(1,482		)	(915		)	—			32,087
Capital Expenditures	98,772		1,593		(1)	2,770			—			103,135

	2005
($-000’s)
Statement of Operations Information
Revenues	$	343,273	$	—	$	5,556		$	(406	)	$	348,423
Operating income (loss)	55,720		—		(1,558		)	—			54,162
Income (loss) from continuing operations	26,249		—		(1,656		)	—			24,593
Capital Expenditures	51,720		—		2,423			—			54,143

	As of September 30,
	2006
	Electric		Gas		Other		Eliminations(2)			Total
	($-000’s)
Balance Sheet Information
Total assets	$	1,202,980	$	120,445	$	21,438	$	(76,783	)	$	1,268,080

	As of December 31,
	2005
Balance Sheet Information
Total assets	$	1,119,773	$	—	$	26,396	$	(24,139	)	$	1,122,030

(1) Does not include the $103,190 acquisition of the Missouri Gas assets.

(2)Reflects the elimination of the “Investment in subsidiaries” recorded in the accounts of the regulated segment

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Note 14 — Discontinued Operations

On August 31, 2006, we sold our controlling 52% interest in MAPP to other current owners. MAPP is a company that specializes in close-tolerance custom manufacturing for the aerospace, electronics, telecommunications and machinery industries. We have reported MAPP’s results as discontinued operations. A summary of the operating results from the discontinued operations of MAPP for all periods reported as of September 30, 2006 follows:

	Three Months Ended			Nine Months Ended			Twelve Months Ended
($-000’s)
Sales	$	1,904.1		$	8,926.8		$	15,209.1
Income/(losses)	(136.3		)	(368.3		)	(35.7		)
Gain on disposal (net of tax)	271.6			271.6			271.6

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 44 communities in northwest, north central and west central Missouri. Gas revenues accounted for 3.8% of our gross operating revenues during the third quarter of 2006. Our other segment includes investments in certain non-regulated businesses including fiber optics, Internet access and customer information system software services. These businesses are held in our wholly-owned subsidiary, EDE Holdings, Inc. In 2005, 92.9% of our gross operating revenues were provided from the sale of electricity, 0.4% from the sale of water and 6.7% from our non-regulated businesses. On August 31, 2006, we sold our controlling 52% interest in MAPP, a non-regulated company that specializes in close-tolerance custom manufacturing.

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

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utility commissions in the states in which we operate, as well as the Federal Energy Regulatory Commission (FERC), set the rates at which we can charge our customers. In order to offset expenses, we depend on our ability to receive adequate and timely 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 1.6% to 1.8% over the next several years, although our electric customer growth for the twelve months ended September 30, 2006 was 2.1%. 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, (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 Missouri Public Service Commission (MPSC) sets the rates at 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, we have agreed with the MPSC to not file a rate increase request for non-gas costs for a period of 36 months following the closing date of the acquisition. A Purchased Gas Adjustment (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 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. As a result, for the company as a whole we expect our acquisition of Missouri Gas to allow us to help diversify our weather risk, balancing our current summer air conditioning peak with a natural gas winter heating peak.

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 recovered from our customers, any change in gas prices does not have a corresponding impact on income unless such costs are deemed imprudent.

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Earnings

During the third quarter of 2006, basic and diluted earnings per weighted average share of common stock were $0.74 as compared to $0.75 in the third quarter of 2005. For the nine months ended September 30, 2006, basic and diluted earnings per weighted average share of common stock were $1.12 as compared to $0.87 for the nine months ended September 30, 2005. For the twelve months ended September 30, 2006, basic and diluted earnings per weighted average share of common stock were $1.19 as compared to $0.95 for the twelve months ended September 30, 2005. All of the above amounts are reflected after the effect of discontinued operations. The effect of discontinued operations increased earnings per share by $0.01 in each period. As reflected in the table below, the primary positive driver for all periods was increased revenues, while a primary negative driver for all periods was increased purchased power costs. Another primary negative driver for the twelve months ended September 30, 2006 was increased fuel costs while another primary driver for the third quarter of 2006 was dilution from our June 21, 2006 sale of 3,795,000 shares of our common stock.

The following reconciliation of basic earnings per share between the three months, nine months and twelve months ended September 30, 2005 versus September 30, 2006 is a non-GAAP presentation. We believe this information is useful in understanding the fluctuation in earnings per share between the prior and current year periods. The reconciliation presents the after tax impact of significant items and components of the statement of operations on a per share basis before the impact of additional stock issuances which is presented separately. Earnings per share for the three months, nine months and twelve months ended September 30, 2006 and 2005 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 — 2005	$	0.75		$	0.87		$	0.95
Revenues
Electric on- system	$	0.20		$	0.61		$	0.98
Electric off — system and other	(0.03		)	(0.01		)	0.06
Gas*	0.13			0.17			0.17
Water	0.00			0.01			0.01
Non — regulated	0.00			0.00			0.01
Expenses
Electric fuel	0.08			0.18			(0.23		)
Purchased power	(0.06		)	(0.33		)	(0.39		)
Cost of natural gas*	(0.06		)	(0.08		)	(0.08		)
Health care and pension — electric segment	0.00			0.05			0.08
Regulated — electric segment (excluding health care and pension)	0.01			(0.01		)	(0.01		)
Regulated — gas segment	(0.06		)	(0.08		)	(0.08		)
Non — regulated	0.00			0.01			0.01
Maintenance and repairs	(0.03		)	(0.03		)	(0.05		)
Depreciation and amortization	(0.02		)	(0.07		)	(0.11		)
Other taxes	(0.01		)	(0.01		)	(0.02		)
Interest charges	(0.02		)	(0.03		)	(0.03		)
Other income and deductions	(0.02		)	(0.05		)	(0.02		)
Dilutive effect of additional shares	(0.12		)	(0.08		)	(0.06		)
Earnings Per Share — 2006	$	0.74		$	1.12		$	1.19

*Gas revenues and expenses for the nine months and twelve months ended represent only the months of June-September 2006.

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Recent Activities

Missouri Gas

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. (Missouri Gas). The Missouri Gas properties consist of approximately 48,500 customers in 44 Missouri communities in northwest, north central and west central Missouri. The base purchase price, originally $84 million in cash, plus working capital and subject to net plant adjustments, was increased to $85 million in February 2006 due to an amendment to the purchase agreement where Aquila, Inc. agreed to retain certain liabilities and obligations originally to have been assumed by us. This transaction was subject to the approval of the MPSC. On March 1, 2006, we, Aquila, Inc., the MPSC staff, the Office of the Public Counsel (OPC) and three intervenors filed a unanimous stipulation and agreement with the MPSC, requesting it approve the proposed transaction. On April 18, 2006, the MPSC issued an Order Approving Unanimous Stipulation and Agreement and Granting a Certificate of Public Convenience and Necessity, effective May 1, 2006. We announced the completion of this acquisition on June 1, 2006. The total purchase price paid to Aquila, Inc., including working capital and net plant adjustments of $17.1 million (subject to post-closing adjustment), was $102.1 million, not including acquisition costs. The acquisition was initially financed by $55 million of privately placed 6.82% First Mortgage Bonds due 2036 issued by EDG, and with short-term debt issued by EDE. This short-term debt was repaid with the proceeds of the sale of our common stock on June 21, 2006. For additional information, see See Note 3 — “Acquisition of Missouri Natural Gas Distribution Operations” and “-Results of Operations- Liquidity and Capital Resources- Financing Activities” below.

Employee Matters

On May 6, 2006, Aquila Union Locals 814 and 695 both ratified a new contract with EDG. This agreement brings three currently separate contracts into one new three-year agreement. As of September 30, 2006, we had 57 gas company employees; 19 non-union and 38 union.

The EDE contract with Local 1474 of The International Brotherhood of Electrical Workers (IBEW) expired on November 1, 2006. Neither party chose to terminate the agreement, and, under its terms, the agreement has been extended until November 1, 2007. We anticipate negotiations on a new contract to commence in the summer of 2007.

Energy Supply

We entered into an agreement with Kansas City Power & Light (KCP&L) on June 13, 2006 to purchase an undivided ownership interest in the proposed coal-fired Iatan 2. We will own 12%, or approximately 100 megawatts, of the proposed 850-megawatt unit. KCP&L, which owns 54.7% of the unit, publicly reported in its 2005 10-K that it expects its share of the total construction costs to be $733 million. Over the last several months, KCP&L has finalized contracts and received bids for the largest cost components of the construction of Iatan No. 2. KCP&L recently announced that the estimated costs for Iatan No. 2 have increased due to constrained labor and material resources. KCP&L also stated that it has approximately 60% of the total estimated cost of Iatan No. 2 under firm contract as of September 30. 2006, and has started construction activities at the site. An owners’ engineer has been hired and the engineering design for Iatan Station is approximately 25% complete, which is on schedule with the targeted project completion in summer 2010.

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The disclosure in KCP&L’s 2005 10-K equates to a total estimated construction budget for Iatan 2 of approximately $1.34 billion. As noted above, however, costs have increased. Although KCP&L has not stated specifically how much costs for Iatan 2 have increased, it has stated that the overall cost estimates of its comprehensive energy plan are currently expected to be about 20% above the estimate in its 2005 Form 10-K. Assuming this 20% increase applied to Iatan 2 (as the high end of the range), the total project cost would be increased to approximately $1.6 billion and our share of the Iatan 2 costs would increase from $160.8 million to approximately $190 million. We currently anticipate spending $14 million in 2006, $48 million in 2007 and $64 million in 2008 for our share of Iatan 2 with additional expenditures in 2009 and 2010. At September 30, 2006, we have spent approximately $7.5 million on this project.

As a requirement for the air permit for Iatan 2, additional emission control equipment is required for Iatan 1. Iatan 1 environmental upgrades are on schedule with approximately 80% of the total estimated costs under firm contract as of September 30, 2006. Our estimated share of the environmental retrofit costs at Iatan 1 are estimated at $45 million and will be expended between 2006 and the end of 2008. At September 30, 2006, we have spent approximately $0.9 million on this project.

On March 14, 2006, we entered into contracts to add 100 megawatts of power to our system. This power will come from the Plum Point Energy Station, a new 665-megawatt, coal-fired generating facility which will be built near Osceola, Arkansas beginning in the spring of 2006 with completion scheduled for 2010. Initially we will own, through an undivided interest, 50 megawatts of the project’s capacity. We also have a long term purchased power agreement for an additional 50 megawatts of capacity and have the option to convert the 50 megawatts covered by the purchased power agreement into an ownership interest in 2015. We currently anticipate spending $20 million in 2006 (of which $14.9 million has been funded at September 30, 2006), $23.3 million in 2007 and $23.9 million in 2008 for construction expenses relating to our 50 megawatt ownership share of Plum Point with additional expenditures in 2009 and 2010.

Plum Point and Iatan 2, are important components of a long-term, least-cost resource plan to add coal-fired generation to our system by mid-2010. The plan is driven by the continued growth in our service area and the expiration of a major purchased power contract in 2010.

At September 30, 2006, the construction at our Riverton plant was still on schedule for the installation of our new 155 megawatt Siemens V84.3A2 combustion turbine, which is scheduled to be operational in the spring of 2007.

Coal conservation was not a major factor in the third quarter of 2006 at any of our coal-fired resources (Asbury, Riverton, Iatan or Westar Energy, with whom we have a purchased power contract). Our coal inventory levels at Riverton and Asbury are still somewhat below target levels due to railroad transportation problems delivering Western coal but our inventory situation has improved and stabilized. As of September 30, 2006, we had approximately 39 days of Western coal inventory at our Riverton plant and approximately 53-58 days (depending on the actual blend ratio) of Western coal inventory at our Asbury plant, compared to 34 days and approximately 53-55 days, respectively, as of June 30, 2006 and approximately 27 days and 27-40 days, respectively, as of December 31, 2005. Our average coal inventory target is 60 days at both plants. Rail transportation issues have also improved at Iatan, although Iatan’s coal supply continues to be below target levels.

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, 2006, compared to the same periods ended September 30, 2005. We operate our businesses as three segments: electric, gas

30

and other. 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. 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 44 communities in northwest, north central and west central Missouri. Our other segment includes investments in certain non-regulated businesses including fiber optics, Internet access and customer information system software services. These businesses are held in our wholly-owned subsidiary, EDE Holdings, Inc.

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)	2006			2005			2006			2005			2006			2005
Income from continuing operations
Electric	$	23.4		$	19.8		$	33.2		$	23.6		$	34.5		$	26.2
Gas	(1.1		)	—			(1.5		)	—			(1.5		)	—
Other	(0.1		)	(0.3		)	(0.8		)	(1.2		)	(0.9		)	(1.6		)
Income from continuing operations	$	22.2		$	19.5		$	30.9		$	22.4		$	32.1		$	24.6
Income from discontinued operations	0.2			0.1			0.2			0.1			0.2			(0.1		)
Net income	$	22.4		$	19.6		$	31.1		$	22.5		$	32.3		$	24.5

Electric Segment

Our electric segment income from continuing operations for the third quarter of 2006 was $23.4 million as compared to $19.8 million for the same period in 2005.

Operating Revenues and Kilowatt-Hour Sales

Of our total electric operating revenues during the third quarter of 2006, approximately 42.4% were from residential customers, 31.1% from commercial customers, 16.1% from industrial customers, 4.2% from wholesale on-system customers, 3.1% from wholesale off-system transactions and 3.1% from miscellaneous sources, primarily transmission services. The breakdown of our electric customer classes has not significantly changed from the third quarter of 2005.

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

kWh Sales (in millions)

	3 Months	3 Months			9 Months	9 Months			12 Months	12 Months
	Ended	Ended	%		Ended	Ended	%		Ended	Ended	%
	2006	2005	Change*		2006	2005	Change*		2006	2005	Change*
Residential	589.6	559.4	5.4	%	1,456.0	1,440.0	1.1	%	1,897.4	1,840.3	3.1	%
Commercial	470.5	432.9	8.7		1,172.8	1,116.6	5.0		1,541.2	1,465.3	5.2
Industrial	314.7	305.9	2.9		869.6	829.3	4.9		1,147.0	1,093.9	4.9
Wholesale On-System	96.9	95.8	1.2		258.3	250.5	3.1		336.6	324.5	3.8
Other**	31.5	30.4	3.5		84.5	83.9	0.8		113.6	111.1	2.3
Total On-System	1,503.2	1,424.4	5.5		3,841.2	3,720.3	3.3		5,035.8	4,835.1	4.2

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Operating Revenues
($ in millions)

	3 Months		3 Months				9 Months		9 Months				12 Months		12 Months
	Ended		Ended		%		Ended		Ended		%		Ended		Ended		%
	2006***		2005		Change*		2006***		2005		Change*		2006***		2005		Change*
Residential	$	52.9	$	49.8	6.3	%	$	123.7	$	114.8	7.8	%	$	158.1	$	143.0	10.6	%
Commercial	38.9		35.5		9.4		88.5		80.7		9.7		113.9		101.9		11.8
Industrial	20.0		19.1		4.9		50.2		45.2		11.0		64.6		57.0		13.3
Wholesale On-System	5.2		4.8		7.3		13.8		12.3		11.9		18.0		15.4		17.2
Other**	2.7		2.6		4.0		6.8		6.4		6.6		9.0		8.1		10.3
Total On-System	$	119.7	$	111.8	7.0		$	283.0	$	259.4	9.1		$	363.6	$	325.4	11.8

*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.

***Revenues include approximately $2.5 million of the Interim Energy Charge collected in the third quarter of 2006, approximately $6.6 million collected in the nine months ended September 30, 2006 and approximately $8.7 million collected in the twelve months ended September 30, 2006 that are not expected to be refunded to customers. See discussion below.

On-System Electric Transactions

Quarter vs. Quarter

For the quarter ended September 30, 2006, kWh sales to our on-system customers increased 5.5% while the associated revenues increased approximately $7.9 million, or 7.0%. The January 2006 Kansas rate increase (discussed below) contributed an estimated $1.6 million to revenues in the third quarter of 2006 while strong sales growth contributed an estimated $4.2 million. Additionally, a revision to our estimate of unbilled revenues contributed $5.9 million to revenues this quarter. Weather, combined with other related factors, had an estimated negative effect of $3.8 million during the quarter. Total cooling degree days (the cumulative number of degrees that the average temperature for each day during that period was above 65° F) for the third quarter of 2006 were 7.1% less than the same period last year but 16.9% more than the 30-year average. The collected IEC which is not expected to be refunded was approximately the same during the third quarter of 2006 as in the same period in 2005. We expect our annual electric customer growth to range from approximately 1.6% to 1.8% over the next several years, although our electric customer growth for the twelve months ended September 30, 2006, was 2.1%.

The increase in residential and commercial kWh sales and associated revenues during the third quarter of 2006 was primarily due to the strong sales growth and the increase in our estimate of unbilled revenue. Revenues were also positively affected by the January 2006 Kansas rate increase.

Industrial kWh sales and revenues, which are not particularly weather sensitive, increased for the third quarter of 2006 mainly due to strong sales growth and the increase in our estimate of unbilled revenues. The increased revenues also reflected the Kansas rate increase.

On-system wholesale kWh sales increased during the third quarter of 2006 due mainly to the continued sales growth. Revenues associated with these FERC-regulated sales increased more than the kWh sales as a result of the fuel adjustment clause applicable to such sales. This clause permits the distribution to customers of changes in fuel and purchased power costs.

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Nine Months vs. Nine Months

For the nine months ended September 30, 2006, kWh sales to our on-system customers increased 3.3% while the associated revenues increased approximately $23.6 million, or 9.1%. Rate increases contributed an estimated $13.7 million to revenues with strong sales growth adding an estimated $7.4 million. Additionally, a revision to our estimate of unbilled revenues contributed $5.9 million to revenues this period. The collected IEC which is not expected to be refunded contributed approximately $2.0 million during the nine months ended September 30, 2006 while weather and other related factors combined to decrease revenues an estimated $5.4 million. Residential kWh sales and related revenues increased due to the strong sales growth and the increase in our estimate of unbilled revenues. Residential revenues also increased due to the March 2005 Missouri rate increase, May 2005 Arkansas rate increase and January 2006 Kansas rate increase. Commercial and industrial kWh sales and revenues increased mainly due to the continued sales growth and the increase in our estimate of unbilled revenues, while associated revenues increased due to the Missouri, Arkansas and Kansas rate increases. On-system wholesale kWh sales increased during the nine months ended 2006 due mainly to continued sales growth while the revenues associated with these FERC-regulated sales increased as a result of the fuel adjustment clause applicable to such sales.

Twelve Months vs. Twelve Months

For the twelve months ended September 30, 2006, kWh sales to our on-system customers increased 4.2% with the associated revenues increasing approximately $38.2 million. The 2005 Missouri and Arkansas rate increases and the 2006 Kansas rate increase contributed an estimated $21.5 million to revenues while strong sales growth contributed an estimated $9.3 million. Additionally, a revision to our estimate of unbilled revenues contributed $5.9 million to revenues this period. Weather and other related factors combined to decrease revenues an estimated $2.6 million while the collected IEC that is not expected to be refunded contributed approximately $4.1 million. Residential and commercial kWh sales and associated revenues increased primarily due to the strong sales growth and the increase in our estimate of unbilled revenues while revenues also increased due to the Missouri, Arkansas and Kansas rate increases. Industrial sales and associated revenues increased during the twelve months ended September 30, 2006 primarily due to the strong sales growth, the increase in our estimate of unbilled revenues discussed above and the aforementioned rate increases. On-system wholesale kWh sales and revenues increased for the twelve months ended September 30, 2006 reflecting the continued sales growth discussed above and the operation of the fuel adjustment clause applicable to these FERC regulated 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:

	2006						2005
	Three Months		Nine Months		Twelve Months		Three Months		Nine Months		Twelve Months
	Ended		Ended		Ended		Ended		Ended		Ended
(in millions)
Revenues	$	4.4	$	11.4	$	15.7	$	5.8	$	12.6	$	14.4
Expenses	3.2		8.1		11.4		4.3		8.7		9.8
Netl	$	1.2	$	3.3	$	4.3	$	1.5	$	3.9	$	4.6

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Revenues less expenses decreased during the third quarter of 2006 as compared to the same period in 2005 due to less market demand for our gas-fired generation as compared to the third quarter of 2005 when there was a shortage of available coal fired generation on the open market. Companies that normally would have coal-fired energy to sell in the market were not doing so in 2005 due to coal shortages, pushing demand onto the gas-fired units. Revenues less expenses also decreased during both the nine month and twelve month periods ended September 30, 2006 as compared to 2005 due to decreased market demand resulting from mild weather in the first quarter of 2006 as well as less market demand for gas-fired energy in the third quarter of 2006 as compared to the same periods in 2005. The related expenses are included in our discussion of purchased power costs below.

Operating Revenue Deductions

Quarter vs. Quarter

During the third quarter of 2006, total electric segment operating expenses increased approximately $3.5 million (3.8%) compared with the same period last year. Electric generation fuel costs decreased approximately $3.0 million (8.1%) while purchased power costs increased approximately $2.6 million (20.9%) during the third quarter of 2006. The decrease in fuel costs was primarily due to decreased generation by our gas fired units in the third quarter of 2006 (an estimated $2.7 million) partially offset by higher prices for the hedged natural gas that we burned in our gas-fired units (an estimated $1.0 million). The third quarter 2005 fuel costs reflect a $5 million one-time pre-tax gain from unwinding part of a physical purchase of natural gas for the 2009 through 2011 period as part of our fuel management process. This gain was recognized in the third quarter of 2005 as a decrease to fuel expense. Increased coal costs contributed an estimated $1.1 million to the total fuel cost partially offset by decreased generation by our coal fired units of an estimated $0.4 million. The increase in purchased power costs primarily reflected our purchase of the output of the Elk River Windfarm. The net decrease in fuel and purchased power during the third quarter of 2006 as compared to the same period last year was $0.4 million (0.9%).

Regulated — other operating expenses for our electric segment decreased approximately $0.1 million (1.1%) during the third quarter of 2006 as compared to the same period in 2005 mainly due to an approximate $0.3 million decrease in transmission and distribution expense and an approximate $0.1 million decrease in our employee health care expenses. These decreases were partially offset by an approximate $0.2 million increase in customer assistance expense and an approximate $0.2 million increase in our employee pension expense.

Maintenance and repairs expense increased approximately $0.7 million (15.5%) as compared to the third quarter of 2005 mainly due to an approximate $0.3 million increase in transmission and distribution maintenance, an approximate $0.2 million increase in maintenance and repairs expense for our State Line Combined Cycle (SLCC) plant and an approximate $0.1 million increase in maintenance and repairs expense for our State Line Unit 1 plant.

Depreciation and amortization expense increased approximately $0.4 million (4.0%) during the quarter mainly due to increased plant in service. Other taxes were virtually the same for the third quarter of 2006 as for the third quarter of 2005.

Nine Months vs. Nine Months

During the nine months ended September 30, 2006, total electric segment operating expenses increased approximately $13.5 million (5.9%) compared with the same period last year. Fuel costs

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decreased approximately $7.1 million (8.5%) but were offset by a $12.9 million (35.7%) increase in purchased power costs during the period. The decrease in fuel costs was primarily due to decreased generation by our gas fired units (an estimated $16.2 million) partially offset by higher prices for the hedged natural gas that we burned in our gas-fired units and losses on the sale of excess gas in the first quarter of 2006 (an estimated $7.7 million) as compared to the first nine months of 2005. The 2005 nine months ended fuel costs reflect a $5 million one-time pre-tax gain from unwinding part of a physical purchase of natural gas for the 2009 through 2011 period as part of our fuel management process. This gain was recognized in the third quarter of 2005 as a decrease to fuel expense. Increased generation by our more economical coal fired units increased fuel costs an estimated $1.5 million in 2006 while increased coal costs contributed an estimated $1.7 million to the total fuel cost. The increase in purchased power costs primarily reflected our purchase of the output of the Elk River Windfarm and also reflected a February 2006 outage at our Asbury plant. The net increase in fuel and purchased power costs during the nine months ended September 30, 2006 as compared to the same period last year was $5.7 million (4.7%).

Regulated - other operating expenses for our electric segment for the first nine months of 2006 decreased approximately $1.4 million (3.5%). Decreased expenses relating to employee health care expenses, our employee pension expense, property insurance expense and distribution expense contributed approximately $1.5 million, $0.5 million, $0.2 million and $0.2 million, respectively, to this decrease. These decreases were partially offset by an approximate $0.4 million increase in professional services expense, an approximate $0.4 million increase in customer assistance expense, an approximate $0.3 million increase in general labor costs, Effective with the second quarter of 2005, we began deferring a portion of our pension cost into a regulatory asset as authorized in our 2005 Missouri rate case. We have deferred approximately $2.1 million as of September 30, 2006. For additional information, see “-Results of Operations- Rate Matters” below.

Maintenance and repairs expense increased $0.5 million (3.3%) for the nine months ended September 30, 2006 compared to the same period in 2005 primarily due to a $0.8 million increase in maintenance and repairs expense for our SLCC plant, a $0.6 million increase in transmission and distribution maintenance expense and a $0.2 million increase in maintenance and repairs expense at our Asbury plant. These increases were partially offset by a $0.6 million decrease in maintenance and repairs expense at our Iatan plant and a $0.5 million decrease at our Energy Center plant. The decrease in maintenance and repairs expense at our Iatan plant related to an outage in 2005 while the decrease in maintenance and repairs expense at our Energy Center plant related to generator repairs in the second quarter of 2005. The increase in maintenance and repairs expense at our SLCC plant is related to the 2006 spring outage.

Depreciation and amortization expense increased approximately $2.2 million (8.9%) during the nine-month period due to higher depreciation rates that became effective on March 27, 2005 and increased plant in service. Other taxes increased $0.2 million (1.3%) during the nine months ended September 30, 2006 due to increased property taxes reflecting our additions to plant in service and increased municipal franchise taxes.

Twelve Months vs. Twelve Months

During the twelve months ended September 30, 2006, total electric segment operating expenses increased approximately $32.6 million (11.3%) compared to the year ago period. Total fuel costs increased approximately $9.1 million (9.4%) during the twelve months ended September 30, 2006 while purchased power costs increased approximately $15.0 million (29.7%) during the same period. The increase in fuel costs was primarily due to higher prices for both the hedged and unhedged natural gas that we burned in our gas-fired units (an estimated $17.0 million) partially offset by decreased generation by our gas-fired units (an estimated $10.4 million). Increased coal

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costs contributed an estimated $2.9 million to the total fuel cost and increased generation by our coal fired units added an estimated $1.6 million. These increased costs reflect a $5 million one-time pre-tax gain from unwinding part of a physical purchase of natural gas for the 2009 through 2011 period as part of our fuel management process. This gain was recognized in the third quarter of 2005 as a decrease to fuel expense. Natural gas prices increased in 2005, in part, from the effects of hurricane activity in the Gulf of Mexico. The increased usage was due in part to weather, as well as changes in the wholesale market impacted by coal delivery issues in the Midwest. The net increase in fuel and purchased power during the twelve months ended September 30, 2006 as compared to the same period last year was $24.1 million (16.4%).

Regulated — other operating expenses for our electric segment decreased approximately $2.4 million (4.4%) during the twelve months ended September 30, 2006 as compared to the same period last year due primarily to a $2.1 million decrease in employee health care expense, a decrease of approximately $1.2 million in employee pension expense a $0.4 million decrease in general administrative expense mainly due to decreased costs associated with Sarbanes-Oxley Section 404 compliance and a $0.4 million decrease in property insurance. These decreases were partially offset by a $0.9 million increase in professional services expense, a $0.4 million increase in customer assistance expense, and a $0.3 million increase in general labor costs.

Maintenance and repairs expense increased approximately $1.3 million (6.7%) during the twelve months ended September 30, 2006, compared to the year ago period primarily reflecting increases of approximately $1.0 million in transmission and distribution maintenance costs and $0.2 million in maintenance costs for our gas-fired units, consisting mainly of a $0.7 million increase in maintenance for our SLCC plant related to the spring 2006 outage and a $0.1 million increase in maintenance for our State Line Unit 1 plant offset by a $0.6 million decrease in maintenance at our Energy Center plant.

Depreciation and amortization expense increased approximately $3.7 million (11.3%) due to higher depreciation rates that became effective on March 27, 2005 and increased plant in service. Other taxes increased $0.3 million (1.6%) during the twelve months ended September 30, 2006 due to increased property taxes reflecting our additions to plant in service and increased municipal franchise taxes.

Gas Segment

Gas Segment Operating Revenues and Sales

During the third quarter of 2006, EDG’s first full quarter of operation, our total natural gas revenues were approximately $4.9 million. For the year-to-date June 2006-September 2006, our total natural gas revenues were approximately $6.6 million. The summer months are low sale months for natural gas companies, whose heating seasons run from November to March of each year.

The following table details our natural gas sales and revenues for the periods ended September 30, 2006:

Total gas delivered to customers - mcf Sales

	2006
	Third Quarter	Year-to-Date*
Residential	146,277.9	198,193.3
Commercial	128,990.7	167,693.1
Industrial	3,400.3	5,368.7
Other public authorities	2,353.0	3,192.6
Total retail sales	281,021.9	374,447.7

*mcf sales represent the months of June through September 2006.

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Operating Revenues ($ in millions)

	2006
	Third Quarter		Year to Date*
Residential	$	2.7	$	3.6
Commercial	1.6		2.2
Industrial	0.1		0.1
Other public authorities	0.0		0.0
Total retail sales revenues	$	4.4	$	5.9
Transportation revenues	0.5		0.6
Total gas operating revenues	$	4.9	$	6.5

*Revenues represent the months of June through September 2006 and exclude forfeited discounts, reconnect fees, miscellaneous service revenues, etc.

Gas Segment Operating Revenue Deductions

During the third quarter of 2006, EDG’s cost of natural gas sold and transported was approximately $2.2 million. For the year-to-date, June 2006 through September 2006, EDG’s cost of natural gas sold and transported was approximately $3.0 million. 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 Clause (PGA) 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 $2.4 million for the third quarter of 2006 and $3.2 million for the year-to-date, June 2006 through September 2006. EDG had net losses of $1.1 million for the third quarter of 2006 and $1.5 million for the year-to-date, June 2006 through September 2006, primarily due to the seasonal nature of EDG and transition costs paid to Aquila, Inc. during these periods. We paid approximately $0.8 million in transition costs to Aquila, Inc. in the third quarter of 2006 (mainly in July and August) and approximately $1.2 million during the year-to-date period for billing and other transition services. The majority of these services ended at the end of August. All services were transitioned by November 1, 2006.

Other Segment

On August 31, 2006, we sold our controlling 52% interest in MAPP to other current owners. MAPP is a company that specializes in close-tolerance custom manufacturing for the aerospace, electronics, telecommunications and machinery industries. We have reported MAPP’s results as discontinued operations. See Note 14 of “Notes to Consolidated Financial Statements (Unaudited)” for the effect of discontinued operations.

Continuing operations from our remaining non-regulated businesses generated a net loss of $0.02 million in the third quarter of 2006 as compared to a $0.3 million net loss in the third quarter of 2005.

During the third quarter of 2006, total other segment operating revenue increased approximately $0.02 million (12.7%) while total other segment operating expense increased approximately $0.01 million (2.9%) as compared to the third quarter of 2005.

Our remaining non-regulated businesses generated a $0.8 million net loss from continuing operations for the nine months ended September 30, 2006 as compared to a $1.2 million net loss for the same period in 2005.

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For the nine months ended September 30, 2006, total non-regulated operating revenue increased approximately $0.4 million (9.2%) while total non-regulated operating expense decreased approximately $0.04 million (0.8%) compared with the same period in 2005.

Our remaining non-regulated businesses generated a $0.9 million net loss from continuing operations for the twelve-months ended September 30, 2006 as compared to a $1.7 million net loss for the same period in 2005.

For the twelve-months ended September 30, 2006, total non-regulated operating revenue increased approximately $0.8 million (14.1%) while total non-regulated operating expense decreased approximately $0.02 million (0.3%) compared with the same period in 2005.

We evaluated our other segment businesses for impairment at December 31, 2005 and believe, based on this analysis, that no impairment exists based on our forecast of future net cash flows. However, failure to achieve forecasted cash flows and execute software license agreements within our software business could result in impairment in the future. We believe that no impairment exists in our other segment businesses as of September 30, 2006.

Consolidated Company

Our consolidated provision for income taxes increased approximately $2.4 million during the third quarter of 2006 as compared to the same period in 2005 due to increased income. Our consolidated effective federal and state income tax rate for the third quarter of 2006 was 35.6% as compared to 33.4% for the third quarter of 2005. The increase in the effective tax rate for the third quarter of 2006 compared to the third quarter of 2005 was mainly due to increased income. In addition, an adjustment for the difference between the amount shown on the income tax returns and the amount accrued for the year 2005 recorded in the third quarter of 2006 accounted for approximately 0.7% of the 2.2% increase.

Our consolidated provision for income taxes increased approximately $5.6 million during the nine months ended September 30, 2006 as compared to the same period in 2005 due to increased income. Our consolidated effective federal and state income tax rate for the nine months ended September 30, 2006 was 35.3% as compared to 33.4% for the same period in 2005.

Our consolidated provision for income taxes increased approximately $5.1 million during the twelve months ended September 30, 2006 as compared to the same period in 2005 due to increased income. Our consolidated effective federal and state income tax rate for the twelve months ended September 30, 2006 was 35.2% as compared to 33.7% for the same period in 2005.

Other Information

Nonoperating Items

Total allowance for funds used during construction (AFUDC) increased $0.8 million during the third quarter of 2006, $1.7 million during the nine months ended September 30, 2006 and $1.9 million during the twelve months ended September 30, 2006 as compared to the prior year periods, due to higher levels of construction in 2006.

Total interest charges on long-term debt increased $0.9 million for the third quarter of 2006, $1.1 million for the nine months ended September 30, 2006 and $0.9 million during the twelve months ended September 30, 2006 as compared to the same periods in 2005, reflecting 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. See “-Liquidity and Capital Resources” for further information. Short-term debt interest increased $0.4 million during the third quarter of 2006, $1.5 million for the nine months ended September 30, 2006 and $1.6 million for the

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twelve months ended September 30, 2006 as compared to the same periods in 2005, reflecting increased usage of short-term debt.

Income from discontinued operations was $0.1 million higher this quarter versus last year due to the gain on the sale of MAPP.

Other Comprehensive Income

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

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

	3 Months Ended			3 Months Ended			9 Months Ended			9 Months Ended			12 Months Ended			12 Months Ended
	2006			2005			2006			2005			2006			2005
Natural gas contracts settled(1)	$	0.5		$	3.4		$	1.3		$	3.6		$	2.0		$	5.9
Interest rate contracts settled	0.0			0.0			0.0			(1.4		)	0.0			(1.4		)
Total contracts settled	$	0.5		$	3.4		$	1.3		$	2.2		$	2.0		$	4.5
Change in FMV of open contracts for natural gas	$	4.3		$	(15.6	)	$	12.6		$	(33.1	)	$	16.8		$	(29.7	)
Change in FMV of open contracts for interest rates	0.0			0.0			0.0			1.4			0.0			1.4
Total change in FMV of contracts	$	4.3		$	(15.6	)	$	12.6		$	(31.7	)	$	16.8		$	(28.3	)
Taxes - natural gas	$	(1.8	)	$	4.6		$	(5.3	)	$	11.2		$	(7.1	)	$	9.0
Taxes — interest rates	0.0			0.0			0.0			0.0			0.0			0.0
Total taxes	$	(1.8	)	$	4.6		$	(5.3	)	$	11.2		$	(7.1	)	$	9.0
Total change in OCI (increase)/decrease - net of tax	$	3.0		$	(7.6	)	$	8.6		$	(18.3	)	$	11.7		$	(14.8	)

 (1) Reflected in fuel expense

Our average cost for our open natural gas hedges increased from $5.948/Dth at June 30, 2006 to $6.153/Dth at September 30, 2006.

We had entered into an interest rate derivative contract in May 2005 to hedge against the risk of a rise in interest rates impacting our 5.8% Senior Notes due 2035 prior to their issuance on June 27, 2005. Costs associated with the interest rate derivative (primarily due to interest rate fluctuations) amounted to approximately $1.4 million and were recorded as a regulatory asset and are being amortized over the life of the 2035 Notes. The $1.2 million redemption premium paid in connection with the redemption of the $30 million aggregate principal amount of our First Mortgage Bonds, 7.75% Series due 2025 redeemed in June 2005, together with $2.4 million of remaining unamortized loss on reacquired debt and $0.3 million of unamortized debt expense, were recorded as a regulatory asset and are being amortized as interest expense over the life of the 2035 Notes.

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Rate Matters

Electric Segment

The following table sets forth information regarding electric and water rate increases since January 1, 2005:

		Annual		Percent
	Date	Increase		Increase		Date
Jurisdiction	Requested	Granted		Granted		Effective
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
Arkansas - Electric	July 14, 2004	595,000		7.66	%	May 14, 2005
Missouri - Electric	April 30, 2004	25,705,500		9.96	%	March 27, 2005

Missouri

On April 30, 2004, we filed a request with the MPSC for an annual increase in base rates for our Missouri electric customers in the amount of $38,282,294, or 14.82%. On December 22, 2004, we, the MPSC Staff, the OPC and two intervenors filed a unanimous Stipulation and Agreement as to Certain Issues with the MPSC settling several issues. One of the issues we were able to agree on was a change in the recognition of pension costs allowing us to defer the Missouri portion of any costs above the amount included in this rate case as a regulatory asset. The amount of pension cost allowed in this rate case was approximately $3.0 million. This stipulation became effective on March 27, 2005 as part of the final Missouri order described below. Therefore, the deferral of these costs began in the second quarter of 2005.

The MPSC issued a final order on March 10, 2005 approving an annual increase in base rates of approximately $25,705,500, or 9.96%, effective March 27, 2005. The order granted us a return on equity of 11%, an increase in base rates for fuel and purchased power at $24.68/MWH and an increase in depreciation rates. The new depreciation rates now include a cost of removal component of mass property (transmission, distribution and general plant costs). In addition, the order approved an annual IEC of approximately $8.2 million effective March 27, 2005 and expiring three years later. The IEC is $0.002131 per kilowatt hour of customer usage. The MPSC allowed us to use forecasted fuel costs rather than the traditional historical costs in determining the fuel portion of the rate increase. At the end of two years, an assessment will be made of the money collected from customers compared to the greater of the actual and prudently incurred costs or the base cost of fuel and purchased power set in rates. If the excess of the amount collected over the greater of these two amounts is greater than $10 million, the excess over $10 million will be refunded to the customers. The entire excess amount of IEC, not previously refunded, will be refunded at the end of three years, unless the IEC is terminated earlier. Each refund will include interest at the current prime rate at the time of the refund. The IEC revenues recorded in every quarter since the inception of the IEC have not recovered all the Missouri related fuel and purchased power costs incurred in those quarters. From inception of the IEC through September 30, 2006, the costs of fuel and purchased power were approximately $23.9 million higher than the total of the costs in our base rates and the IEC recorded during the period. Future recovery of fuel and purchased power costs through the IEC are dependent upon a variety of factors, including natural gas prices, costs of non-contract purchased power, weather conditions, plant availability and coal deliveries. At September 30, 2006, no provision for refund has been recorded.

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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 expect the high natural gas prices to continue to negatively impact our fuel and purchased power expenses in the near future. Given our limited ability to recover these added costs, we also requested transition from the IEC to Missouri’s new fuel adjustment mechanism. However, the MPSC issued an order May 2, 2006 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. At this time, we cannot predict the outcome of this rate case filing, but, based on Missouri law, we expect it to be finalized no later than December 31, 2006.

On June 24, 2005, we filed a request with the MPSC for an annual increase in base rates for our Missouri water customers in the amount of $523,000, or 38%. The MPSC issued a final order on January 31, 2006 approving an annual increase in base rates of approximately $469,000, or 35.9%, effective February 4, 2006.

Arkansas

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

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 last Missouri rate case. In addition, we will be allowed to change our recognition of pension costs, deferring the Kansas portion of any costs above the amount included in this rate case as a regulatory asset. 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 acquired the Missouri natural gas distribution operations of Aquila, Inc. (Missouri Gas). The Missouri Gas properties consist of approximately 48,500 customers in 44 Missouri communities in northwest, north central and west central Missouri. The gas rates for these properties are set through May 31, 2009, as we have 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. However, we do have a gas cost recovery mechanism in Missouri. We have also agreed, per the above agreement, 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.

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

Environmental

We are subject to various federal, state, and local laws and regulations 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.

The acquisition of Missouri Gas involved the property transfer of two former manufactured gas plant (MGP) sites previously owned by Aquila, Inc. and their predecessors. Site #1 is listed in the Missouri Department of Natural Resources (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. We are reviewing various actions that may be undertaken to reduce environmental and health risks associated with the MDNR Registry site. As of June 1, 2006, we have recorded a liability of approximately $0.3 million for these two sites, most of which is offset by a regulatory asset.

Competition

Electric Segment

SPP-RTO

In 2003, 2004 and 2005 we filed notices of intent with the Southwest Power Pool Regional Transmission Organization (SPP RTO) for the right to withdraw from the SPP RTO effective November of the succeeding year. These notices were given primarily because of uncertainty surrounding the treatment from the states regarding RTO participation and cost recoveries. Such withdrawal requires approval from the FERC. We retained the option, however, to rescind these notices, which we have done as recently as October 31, 2006. Because we have now obtained acceptable regulatory authorizations from Missouri, Kansas and Arkansas for continued participation in and transfer of functional control of our transmission facilities to the SPP RTO, coupled with the fact that a twelve month withdrawal notice can be submitted to the SPP RTO at any time, we have decided to not reissue a notice of intent to withdraw at this time.

On June 13, 2006, the MPSC issued an order approving the Stipulation and Agreement regarding our continued participation in and transfer of functional control of certain transmission facilities to the SPP RTO. Due to needed clarifications regarding the MPSC order, the parties to the agreement, except for the OPC, filed a Motion to Clarify. The Motion to Clarify was granted, and an Amended Order approving the Stipulation and Agreement was issued by the MPSC on July 13, 2006 with an effective date of July 23, 2006. As a condition of the MPSC approval of the Stipulation and Agreement, a Transmission Service Agreement (TSA) between us and the SPP RTO was to be filed and accepted by the FERC. Such filing was made to the FERC on July 31, 2006 and is pending before FERC at this time. Such approval is anticipated before the end of the year since FERC has recently approved a very similar agreement between the SPP RTO and KCP&L.

On July 14, 2006, we jointly filed an uncontested Stipulation and Agreement between ourselves, the other Kansas transmission owning utilities, interveners, and the KCC staff regarding a similar authorization to continue participation in the SPP RTO and transfer functional control of our transmission facilities. An acceptable order from the KCC approving the Stipulation and Agreement (i.e. our continued participation in the SPP RTO and transfer of functional control of certain transmission facilities) was issued on September 19, 2006.

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On November 4, 2005, we filed a request for authorization from the Arkansas Public Service Commission (APSC) for the continued participation in the SPP RTO and transfer of functional control of certain transmission facilities. Such filing was later combined with similar filings of Oklahoma Gas and Electric and American Electric Power — Southwestern Electric Power Company as well as the filing for the Certificate of Public Convenience and Necessity of the SPP RTO. On August 10, 2006, the APSC approved the consolidated filing, including ours, with certain reporting conditions that we found to be acceptable.

The SPP RTO is in the process of finalizing market rules and readiness to implement an energy imbalance services market (EIS) within its market area. The start of the SPP RTO EIS market was recently scheduled to start October 1, 2006, but has experienced start up/readiness delays. At the October 24, 2006 SPP RTO board of directors meeting, a decision was made, due to the lack of SPP and market participant readiness, to delay the start of the market until February 1, 2007. Additional EIS related filings at the FERC will be required by the SPP RTO and us prior to final approval by the FERC for authorization to start the EIS market. We believe that the implementation and operation of the SPP RTO EIS market will provide benefits to our customers and stakeholders. However, we are unable to quantify the potential impact of such EIS participation on our future financial position, results of operation or cash flows at this time. 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.

This 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.

FERC Market 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. Failure to show a lack 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.

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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. Due to the number of requests for rehearing before FERC by other utilities with similar circumstances, it is anticipated that it may be several weeks before FERC will issue an order regarding our request of rehearing and refund requirement. At this time, we cannot predict the outcome of these proceedings.

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

Our net cash flows provided by operating activities decreased approximately $13.3 million during the nine months ended September 30, 2006 as compared to the nine months ended September 30, 2005, primarily due to a $23.2 million decrease in the cash flow changes of working capital partially offset by an $8.6 million increase in net income. Investments were higher due to increased construction and our acquisition of Missouri Gas. Our primary sources of cash flow during the first nine months of 2006 were $73.3 million in internally generated funds, $78.3 million in proceeds from the issuance of common stock and $55.0 million in proceeds from the issuance of EDG first mortgage bonds. Our primary uses of cash during the first nine months of 2006 were our $103.2 million acquisition of Missouri Gas, $89.1 million in capital expenditures and $26.4 million in dividend payments.

Cash Provided by Operating Activities

Our net cash flows provided by operating activities decreased approximately $13.3 million during the nine months ended September 30, 2006 as compared to the nine months ended September 30, 2005. Cash flows were positively impacted by a $19.0 million cash flow change in accounts receivable and an $8.6 million increase in net income, partially offset by a $29.2 million cash flow change in accounts payable and accrued liabilities, a $9.4 million cash flow change in fuel, materials and supplies and a $4.2 million cash flow change in prepaid expenses.

Capital Requirements and Investing Activities

Our net cash flows used in investing activities increased $133.9 million during the nine months ended September 30, 2006 as compared to the nine months ended September 30, 2005, primarily reflecting our acquisition of Missouri Gas, additions to our transmission and distribution systems and construction expenditures for the new combustion turbine at Riverton and for our investment in the Plum Point Energy Station.

Our capital expenditures totaled approximately $35.7 million during the third quarter of 2006 compared to approximately $15.3 million for the same period in 2005. For the nine months ended September 30, 2006, capital expenditures totaled approximately $89.1 million (excluding the acquisition of Missouri Gas) compared to approximately $57.6 million for the same period in 2005. These capital expenditures include AFUDC, capital expenditures to retire assets and benefits from salvage.

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A breakdown of the capital expenditures, acquisition of EDG and other investing activities for the quarter and nine months ended September 30, 2006 is as follows:

	Quarter Ended			Nine Months Ended
	September 30, 2006			September 30, 2006
	(in millions)			(in millions)
Distribution and transmission system additions	$	11.0		$	33.6
Additions and replacements — Asbury	6.2			11.8
Additions and replacements — Riverton, Iatan, Ozark Beach, Energy Center, State Line and State Line Combined Cycle	1.5			2.9
New generation — Riverton combustion turbine	2.6			10.7
New generation — Plum Point Energy Station	3.9			14.9
New generation — Iatan 2	7.2			7.5
Fiber optics (non-regulated)	0.9			2.1
Gas	1.2			1.6
Storms	0.0			0.9
Transportation	1.3			1.4
Other non-regulated capital expenditures	(0.3		)	—
Other	0.2			0.9
Retirements and salvage (net)	0.0			0.8
Subtotal	$	35.7		$	89.1
Acquisition of EDG	—			103.1
Sale of MAPP	(1.1		)	(1.1		)
Discontinued operations	0.3			0.3
TOTAL	$	34.9		$	191.4

For the first nine months of 2006, approximately 52% of our cash requirements for capital expenditures (excluding the acquisition of Missouri Gas) 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 2006 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 6 of “Notes to Consolidated Financial Statements (Unaudited)”.

Financing Activities

Financing activities increased net cash by $137.5 million during the nine months ended September 30, 2006 as compared to the nine months ended September 30, 2005, resulting in $106.1 million of cash provided in the current year. Our net cash flows provided by financing activities were primarily affected by increased proceeds from the issuance of common stock and EDG first mortgage bonds in 2006.

On April 1, 2005, we redeemed our $10 million First Mortgage Bonds, 7.60% Series due April 1, 2005, using short-term debt. On June 27, 2005, we issued $40 million aggregate principal amount of our Senior Notes, 5.8% Series due 2035, for net proceeds of approximately $39.4 million less $0.1 million of legal fees. We used the net proceeds from this issuance to redeem all $30 million aggregate principal amount of our First Mortgage Bonds, 7.75% Series due 2025 for approximately $31.3 million, including interest and a redemption premium, and to repay short-term debt. The $1.2 million redemption premium paid in connection with the redemption of these first mortgage bonds,

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together with $2.4 million of remaining unamortized loss on reacquired debt and $0.3 million of unamortized debt expense, were recorded as a regulatory asset and are being amortized as interest expense over the life of the 2035 Notes. We had entered into an interest rate derivative contract in May 2005 to hedge against the risk of a rise in interest rates impacting the 2035 Notes prior to their issuance. Costs associated with the interest rate derivative (primarily due to interest rate fluctuations) amounted to approximately $1.4 million and were recorded as a regulatory asset and are being amortized over the life of the 2035 Notes.

On June 1, 2006, we used $55 million of privately placed 6.82% First Mortgage Bonds due 2036 issued by EDG to fund a portion of our acquisition of Missouri Gas from Aquila, Inc. We used short-term debt to fund the remainder of the acquisition, which was replaced with common equity on June 21, 2006.

On June 21, 2006, we sold 3,795,000 shares of our common stock, including an additional 495,000 shares to cover the underwriters’ over-allotments, in an underwritten public offering for $20.25 per share. The sale resulted in net proceeds of approximately $73.3 million ($76.8 million less issuance costs of $3.5 million). The proceeds were used to pay down short-term debt, including short-term debt used to fund a portion of our acquisition of Missouri Gas.

We have an effective shelf registration statement with the SEC under which approximately $323.2 million of our common stock, unsecured debt securities, preference stock and first mortgage bonds remain available for issuance. Of this amount, $200 million has been approved by the MPSC as available for first mortgage bonds. We plan to use a portion of the proceeds from issuances under this new 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 will reduce over the next four years in line with the amount of construction expenditures we owe for Plum Point and is $68.5 million as of October 1, 2006. 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, 2006, 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, 2006, however, $40.8 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 Mortgage contains a requirement that for new first mortgage bonds to be issued, our net earnings (as defined in the Mortgage) for any twelve consecutive months within the fifteen months preceding issuance must be two times the annual interest requirements (as defined in the Mortgage) on all first mortgage bonds then outstanding and on the prospective issue of new first mortgage bonds. Our earnings for

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the twelve months ended September 30, 2006 would permit us to issue approximately $353.2 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 Mortgage provides that new bonds must be issued against, among other things, retired bonds or 60% of net property additions. At September 30, 2006, we had retired bonds and net property additions which would enable the issuance of at least $510.5 million principal amount of bonds if the annual interest requirements are met. As of September 30, 2006, we are in compliance with all restrictive covenants of the Mortgage.

Restrictions in the mortgage bond indenture of EDG could affect its liquidity. The 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. The mortgage also contains a limitation on the issuance by EDG of debt (including first mortgage bonds, but excluding short-term debt incurred in the ordinary course under working capital facilities) unless, after giving effect to such issuance, EDG’s ratio of EBIDTA (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, 2006, our corporate credit rating and the ratings for our securities were as follows:

	Standard & Poor’s	Moody’s	Fitch
Corporate Credit Rating	BBB-	Baa2	n/r
First Mortgage Bonds	BBB+	Baa1	BBB+
First Mortgage Bonds - Pollution Control Series	AAA	Aaa	n/r
Senior Notes	BB+	Baa2	BBB
Trust Preferred Securities	BB	Baa3	BBB-
Commercial Paper	A-3	P-2	F2
Outlook	Stable	Stable	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 has 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. Moody’s affirmed our ratings on May 13, 2005 and revised their rating outlook on us from negative to stable.

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

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stable service territory and a seemingly improving regulatory environment in Missouri where we receive approximately 89% of our electric revenues.

These ratings indicate the agencies’ assessment of our ability to pay interest, distributions, dividends and principal on these securities. The lower the rating the higher our financing costs will be when our securities are sold. Ratings below investment grade (investment grade is Baa3 or above for Moody’s and BBB- or above for Standard & Poor’s) may also impair our ability to issue short-term debt, commercial paper or other securities or make the marketing of such securities more difficult.

CONTRACTUAL OBLIGATIONS

Set forth below is information summarizing our contractual obligations as of September 30, 2006. Not included in these amounts are expected obligations associated with our share of the Plum Point Energy Station construction, Iatan 2 construction and Iatan 1 environmental construction additions, the installation of the new combustion turbine at Riverton for which purchase orders have not been opened, postretirement benefit funding or any future pension funding commitments.

	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)	$412.9	$—	$—	$70.0	$342.9
Note payable to securitization trust	50.0	-	-	-	50.0
Interest on long-term debt	516.2	29.6	59.2	51.2	376.2
Short-term debt	40.8	40.8	-	-	-
Capital lease obligations	1.2	0.3	0.6	0.3	-
Operating lease obligations (2)	3.5	0.9	1.7	0.4	0.5
Electric purchase obligations (3)	392.2	74.8	114.2	68.2	135.0
EDG purchase obligations (4)	67.4	14.4	13.7	11.6	27.7
Open purchase orders	42.9	19.4	23.5	-	-
Other long-term liabilities (5)	4.2	0.2	0.4	0.3	3.3
Total Contractual Obligations	$1,531.3	$180.4	$213.3	$202.0	$935.6

(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 agreement, as payments are contingent upon output of the facility. Payments can run from zero up to a maximum of $15.2 million per year based on a 20 year average cost and an annual output of 550,000 megawatt hours.

(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 regulated subsidiary EDG.

(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 starting in January 2007.

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, 2006, our retained earnings balance was $24.4 million, compared to $26.8 million as of

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September 30, 2005, after paying out $26.4 million in dividends during the first nine months of 2006. 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 $1.12 for the nine months ended September 30, 2006 and were $0.92 and $0.86 for the years ended December 31, 2005 and 2004, respectively. Dividends paid per share were $0.96 for the nine months ended September 30, 2006 and $1.28 for each of the years ended December 31, 2005 and 2004.

In addition, the Mortgage and our Restated Articles contain certain dividend restrictions. The most restrictive of these is contained in the Mortgage, which provides that we may not declare or pay any dividends (other than dividends payable in shares of our common stock) or make any other distribution on, or purchase (other than with the proceeds of additional common stock financing) any shares of, our common stock if the cumulative aggregate amount thereof after August 31, 1944 (exclusive of the first quarterly dividend of $98,000 paid after said date) would exceed the earned surplus (as defined in the 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, 2006, 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

Goodwill

We recordedgoodwill upon the completion of the Missouri Gas acquisition of $38.2 million. Goodwill represents the excess of the cost of the acquisition over the fair value of the related net assets at the date of acquisition. In accordance with Statement of Financial Accounting Standards No. 142, “Goodwill and Other Intangible Assets,” goodwill is required to be tested for impairment on an annual basis or whenever events or circumstances indicate possible impairment. Circumstances under which impairment could occur include not realizing anticipated synergies, adverse regulatory treatment or the loss of gas customers. In performing impairment tests, valuation techniques require the use of estimates with regard to discounted future cash flows of operations, involving judgments based on a broad range of information and historical results. If the test indicates impairment has occurred, goodwill would be reduced, adversely impacting earnings.

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, 2005 for a discussion of our other critical accounting policies.

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RECENTLY ISSUED ACCOUNTING STANDARDS

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

Item 3.  Quantitative and Qualitative Disclosures about Market Risk

Market risk is the exposure to a change in the value of a physical asset or financial instrument, derivative or non-derivative, caused by fluctuations in market variables such as interest rates or commodity prices. We handle our commodity market risk in accordance with our established Energy Risk Management Policy, which may include entering into various derivative transactions. We utilize derivatives to manage our gas commodity market risk and to help manage our exposure resulting from purchasing most of our natural gas on the volatile spot market for the generation of power for our native-load customers. See Note 4 of “Notes to Consolidated Financial Statements (Unaudited)” for further information.

Interest Rate Risk. We are exposed to changes in interest rates as a result of financing through our issuance of commercial paper and other short-term debt. We manage our interest rate exposure by limiting our variable-rate exposure (applicable only to commercial paper 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% more in 2006 than in 2005, our interest expense would increase, and income before taxes would decrease by less than $350,000. This amount has been determined by considering the impact of the hypothetical interest rates on our highest month-end commercial paper balance for 2005. These analyses do not consider the effects of the reduced level of overall economic activity that could exist in such an environment. In the event of a significant change in interest rates, management would likely take actions to further mitigate its exposure to the change. However, due to the uncertainty of the specific actions that would be taken and their possible effects, the sensitivity analysis assumes no changes in our financial structure.

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

We satisfied 62.2% of our 2005 generation fuel supply need through coal. Approximately 88% of our 2005 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 coal supply requirements for 2006, 90% of our 2007 requirements, 60% of our 2008 requirements, 30% of our 2009 requirements and 20% 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 have 100% of our coal supply transportation under contract with BNSF and The Kansas City Southern Railway Company under a five-year agreement that became effective June 30, 2005.

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

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27, 2006, 87% of our anticipated volume of natural gas usage for our electric operations for the remainder of year 2006 is hedged at an average price of $6.80 per Dth.

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, 2006, our natural gas expense would increase, and income before taxes would decrease by approximately $1.3 million based on our hedge positions for the next twelve months.

We hedge a portion of our natural gas price risk for our gas operations using derivative contracts. As of October 27, 2006, we have 3.5 million Dths of natural gas hedged, which represents 84% of our expected usage for the winter season (November through March) for our gas operations. 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. As of September 30, 2006 and December 31, 2005, we had margin deposit assets of $2.2 million and $2.1 respectively and margin deposit liabilities of $4.3 million and $7.8 million respectively.

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

Our exposure to credit risk is concentrated primarily within our fuel procurement process, as we transact with a smaller, less diverse group of counterparties and transactions may involve large notional volumes and potentially volatile commodity prices. At September 30, 2006, gross credit exposure related to these transactions totaled $1.7 million, reflecting the unrealized losses 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 pursuant to Rule 13a-15 of the Securities Exchange Act of 1934. Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective, in all material respects, with respect to the recording, processing, summarizing and reporting, within the time periods specified in the SEC’s rules and forms, of information to be required to be disclosed by us in reports that we file or submit under the Exchange Act.

There have been no changes in our internal control over financial reporting that occurred during the third quarter of 2006 that have materially affected or are reasonably likely to materially affect our internal control over financial reporting except for the addition of EDG, our acquired

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Missouri gas operations. As of September 30, 2006, we had incorporated all accounting processes related to the gas operations, with the exception of billing for large transport customers and fuel adjustment clause accounting, into our current procedures and internal control processes. The billing activities for large transport customers were converted to EDG’s internal billing process from Aquila, Inc. as of November 1, 2006. Fuel adjustment clause accounting was incorporated as of November 3, 2006.

PART II.  OTHER INFORMATION

Item 1-A.  Risk Factors.

Except as set forth below, 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, 2005.

We may be unable to recover increases in the cost of natural gas from our natural gas utility customers, or may lose customers as a result of any price increases.

In our natural gas utility business, we are permitted to recover the cost of gas directly from our customers through the use of a purchased gas adjustment provision. However, this provision only permits the recovery of “prudently-incurred” costs. To the extent the MPSC determines that any of our costs were not prudently incurred, we would have to repay any such amounts that we collected from, customers as part of an annual reconciliation. In addition, increases in natural gas costs affect total prices to our customers and, therefore, the competitive position of gas relative to electricity, other forms of energy and other gas suppliers. Increases in natural gas costs may also result in lower usage by customers unable to switch to alternate fuels. Any such disallowed costs or customer losses could have a material adverse effect on our results of operations.

Item 5.  Other Information.

For the twelve months ended September 30, 2006, our ratio of earnings to fixed charges was 2.56x.  See Exhibit (12) hereto.

Item 6.  Exhibits.

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

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

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

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

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

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

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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 6, 2006

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