UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended June 30, 2010 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 S. Joplin Avenue, Joplin, Missouri (Address of principal executive offices)	64801 (zip code)

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

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes o  No  o

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

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

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

As of August 2, 2010, 41,389,561 shares of common stock were outstanding.

THE EMPIRE DISTRICT ELECTRIC COMPANY

INDEX

		PAGE
	Forward Looking Statements	3
Part I -	Financial Information:
Item 1.	Financial Statements:
	a.   Consolidated Statements of Income	4
	b.   Consolidated Statements of Comprehensive Income	7
	c.   Consolidated Balance Sheets	8
	d.   Consolidated Statements of Cash Flows	10
	e.   Notes to Consolidated Financial Statements	11
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	33
	Executive Summary	33
	Results of Operations	38
	Rate Matters	48
	Competition	52
	Liquidity and Capital Resources	54
	Contractual Obligations	59
	Dividends	59
	Off-Balance Sheet Arrangements	60
	Critical Accounting Policies	60
	Recently Issued Accounting Standards	60
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	60
Item 4.	Controls and Procedures	62
Part II-	Other Information:
Item 1.	Legal Proceedings	62
Item 1A.	Risk Factors	63
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds - (none)
Item 3.	Defaults Upon Senior Securities - (none)
Item 5.	Other Information	63
Item 6.	Exhibits	63
	Signatures	64

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:

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

·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;

·volatility in the credit, equity and other financial markets and the resulting impact on our short term debt costs and our ability to issue debt or equity securities, or otherwise secure funds to meet our capital expenditure, dividend and liquidity needs;

·the results of prudency and similar reviews by regulators of costs we incur, including capital expenditures and including Southwest Power Pool (SPP) regional transmission organization (RTO) expansion costs;

·operation of our electric generation facilities and electric and gas transmission and distribution systems, including the performance of our joint owners;

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

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

·legislation;

·regulation, including environmental regulation (such as NOx, SO2, mercury, ash and CO2) and health care regulation;

·competition, including the regional SPP energy imbalance market;

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

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

·changes in accounting requirements;

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

·rate regulation, growth rates, discount rates, capital spending rates, terminal value calculations and other factors integral to the calculations utilized to test the impairment of goodwill, in addition to market and economic conditions which could adversely affect the analysis and ultimately negatively impact earnings;

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

·the performance of our pension assets and other post employment benefit plan assets and the resulting impact on our related funding commitments;

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

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

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

·our exposure to the credit risk of our hedging counterparties; and

·other circumstances affecting anticipated rates, revenues and costs.

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

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

3

PART I.  FINANCIAL INFORMATION

Item 1.  Financial Statements

THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

	Three Months Ended
	June 30
	2010			2009
	(000’s except per share amounts)
Operating revenues:
Electric	$	106,249		$	102,649
Gas	6,516			7,919
Water	436			434
Other	1,281			1,228
	114,482			112,230
Operating revenue deductions:
Fuel and purchased power	44,255			41,548
Cost of natural gas sold and transported	2,265			4,211
Regulated operating expenses	19,272			18,076
Other operating expenses	480			422
Maintenance and repairs	9,600			8,925
Depreciation and amortization	13,586			12,739
Provision for income taxes	4,439			4,028
Other taxes	6,306			6,254
	100,203			96,203
Operating income	14,279			16,027
Other income and (deductions):
Allowance for equity funds used during construction	1,913			1,229
Interest income	52			61
Provision for other income taxes	(46		)	(19		)
Other, net	(256		)	(43		)
	1,663			1,228
Interest charges:
Long-term debt	10,083			10,912
Trust preferred securities	1,027			1,062
Short-term debt	245			206
Allowance for borrowed funds used during construction	(2,430		)	(2,106		)
Other	(352		)	(446		)
	8,573			9,628
Net income	$	7,369		$	7,627
Weighted average number of common shares outstanding - basic	40,623			34,194
Weighted average number of common shares outstanding - diluted	40,654			34,223
Total earnings per weighted average share of common stock — basic and diluted	$	0.18		$	0.22
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 INCOME (UNAUDITED)

	Six Months Ended
	June 30,
	2010			2009
	(000’s except per share amounts)
Operating revenues:
Electric	$	219,849		$	209,011
Gas	31,076			36,006
Water	870			859
Other	2,581			2,369
	254,376			248,245
Operating revenue deductions:
Fuel and purchased power	94,939			88,338
Cost of natural gas sold and transported	17,375			23,519
Regulated operating expenses	38,189			35,577
Other operating expenses	968			831
Maintenance and repairs	17,407			16,592
Depreciation and amortization	26,771			25,412
Provision for income taxes	14,328			9,561
Other taxes	14,042			13,733
	224,019			213,563
Operating income	30,357			34,682
Other income and (deductions):
Allowance for equity funds used during construction	3,653			2,636
Interest income	122			137
Provision for other income taxes	(91		)	(94		)
Other, net	(503		)	35
	3,181			2,714
Interest charges:
Long-term debt	20,568			20,547
Trust preferred securities	2,090			2,125
Short-term debt	490			786
Allowance for borrowed funds used during construction	(4,845		)	(4,303		)
Other	(720		)	(299		)
	17,583			18,856
Net income	$	15,955		$	18,540
Weighted average number of common shares outstanding - basic	39,618			34,129
Weighted average number of common shares outstanding - diluted	39,645			34,155
Total earnings per weighted average share of common stock – basic and diluted	$	0.40		$	0.54
Dividends per share of common stock	$	0.64		$	0.64

See accompanying Notes to Consolidated Financial Statements.

5

THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

	Twelve Months Ended
	June 30,
	2010			2009
	(000’s except per share amounts)
Operating revenues:
Electric	$	443,971		$	446,671
Gas	52,384			65,020
Water	1,774			1,764
Other	5,170			4,727
	503,299			518,182
Operating revenue deductions:
Fuel and purchased power	188,629			188,511
Cost of natural gas sold and transported	29,457			43,151
Regulated operating expenses	75,698			71,934
Other operating expenses	1,937			1,895
Maintenance and repairs	33,827			32,748
Depreciation and amortization	52,853			51,491
Provision for income taxes	24,338			23,600
Other taxes	26,390			26,043
	433,129			439,373
Operating income	70,170			78,809
Other income and (deductions):
Allowance for equity funds used during construction	7,225			5,950
Interest income	202			572
Benefit (provision) for other income taxes	(308		)	178
Other, net	(997		)	(1,073		)
	6,122			5,627
Interest charges:
Long-term debt	42,106			39,677
Trust preferred securities	4,215			4,250
Short-term debt	828			1,796
Allowance for borrowed funds used during construction	(8,466		)	(8,029		)
Other	(1,102		)	287
	37,581			37,981
Net income	$	38,711		$	46,455
Weighted average number of common shares outstanding — basic	37,645			34,025
Weighted average number of common shares outstanding — diluted	37,665			34,067
Total earnings per weighted average share of common stock — basic	$	1.03		$	1.37
Total earnings per weighted average share of common stock — diluted	$	1.03		$	1.36
Dividends per share of common stock	$	1.28		$	1.28

See accompanying Notes to Consolidated Financial Statements.

6

THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	Three Months Ended
	June 30,
	2010			2009
	($-000’s)
Net income	$	7,369		$	7,627
Reclassification adjustments for loss included in net income or reclassified to regulatory asset or liability	950			1,739
Net change in fair market value of derivative contracts for period	676			1,866
Income taxes	(619		)	(1,374		)
Comprehensive income	$	8,376		$	9,858

	Six Months Ended
	June 30,
	2010			2009
	($-000’s)
Net income	$	15,955		$	18,540
Reclassification adjustments for loss included in net income or reclassified to regulatory asset or liability	950			6,665
Net change in fair market value of derivative contracts for period	(5,325		)	(7,467		)
Income taxes	1,667			306
Comprehensive income	$	13,247		$	18,044

	Twelve Months Ended
	June 30,
	2010			2009
	($-000’s)
Net income	$	38,711		$	46,455
Reclassification adjustments for loss included in net income or reclassified to regulatory asset or liability	7,853			5,365
Net change in fair market value of derivative contracts for period	(7,434		)	(58,689		)
Income taxes	(160		)	20,316
Comprehensive income	$	38,970		$	13,447

See accompanying Notes to Consolidated Financial Statements.

7

THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS (UNAUDITED)

	June 30, 2010		December 31, 2009
	($-000’s)
Assets
Plant and property, at original cost:
Electric	$	1,653,852	$	1,619,949
Natural gas	58,987		58,180
Water	11,053		10,891
Other	30,702		29,564
Construction work in progress	321,746		302,012
	2,076,340		2,020,596
Accumulated depreciation and amortization	580,701		561,586
	1,495,639		1,459,010
Current assets:
Cash and cash equivalents	6,728		5,620
Accounts receivable — trade, net	37,873		36,136
Accrued unbilled revenues	20,088		23,717
Accounts receivable — other	15,900		21,417
Fuel, materials and supplies	45,564		43,973
Unrealized gain in fair value of derivative contracts	419		2,782
Prepaid expenses and other	6,950		4,438
Regulatory assets	3,456		772
	136,978		138,855
Noncurrent assets and deferred charges:
Regulatory assets	167,090		168,254
Goodwill	39,492		39,492
Unamortized debt issuance costs	9,841		10,638
Unrealized gain in fair value of derivative contracts	713		2,525
Iatan investment tax credits	17,713		17,713
Other	2,227		3,359
	237,076		241,981
Total Assets	$	1,869,693	$	1,839,846

(Continued)

See accompanying Notes to Consolidated Financial Statements.

8

THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS (UNAUDITED) (Continued)

	June 30, 2010			December 31, 2009
	($-000’s)
Capitalization and Liabilities
Common stock, $1 par value, 41,362,758 and 38,112,280 shares issued and outstanding, respectively	$	41,363		$	38,112
Capital in excess of par value	605,860			551,631
Retained earnings	559			10,068
Accumulated other comprehensive (loss)/income, net of income tax	(2,369		)	339
Total common stockholders’ equity	645,413			600,150
Long-term debt (net of current portion):
Note payable to securitization trust	—			50,000
Obligations under capital lease	2,489			2,563
First mortgage bonds and secured debt	439,096			339,643
Unsecured debt	247,815			247,950
Total long-term debt	689,400			640,156
Total long-term debt and common stockholders’ equity	1,334,813			1,240,306
Current liabilities:
Accounts payable and accrued liabilities	46,640			67,406
Current maturities of long-term debt	865			51,021
Short-term debt	40,000			50,500
Customer deposits	10,535			10,394
Interest accrued	5,470			5,698
Unrealized loss in fair value of derivative contracts	4,365			4,337
Taxes accrued	11,873			3,386
	119,748			192,742
Commitments and contingencies (Note 7)
Noncurrent liabilities and deferred credits:
Regulatory liabilities	83,897			87,533
Deferred income taxes	204,180			194,315
Unamortized investment tax credits	19,977			20,125
Pension and other postretirement benefit obligations	86,640			84,240
Unrealized loss in fair value of derivative contracts	1,925			426
Other	18,513			20,159
	415,132			406,798
Total Capitalization and Liabilities	$	1,869,693		$	1,839,846

See accompanying Notes to Consolidated Financial Statements.

9

THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

	Six Months Ended
	June 30,
	2010			2009
	($-000’s)
Operating activities:
Net income	$	15,955		$	18,540
Adjustments to reconcile net income to cash flows from operating activities:
Depreciation and amortization	30,698			29,903
Pension and other postretirement benefit costs	3,060			2,803
Deferred income taxes and unamortized investment tax credit, net	4,097			5,321
Allowance for equity funds used during construction	(3,653		)	(2,636		)
Stock compensation expense	1,670			1,398
Non-cash loss on derivatives	652			6,034
Gain on sale of assets	—			(504		)
Cash flows impacted by changes in:
Accounts receivable and accrued unbilled revenues	6,246			6,714
Fuel, materials and supplies	(1,591		)	8,077
Prepaid expenses, other current assets and deferred charges	(5,879		)	(3,111		)
Accounts payable and accrued liabilities	(18,806		)	(21,462		)
Customer deposits, interest and taxes accrued	8,400			7,940
Other liabilities and other deferred credits	1,137			968
Net cash provided by operating activities	41,986			59,985
Investing activities:
Capital expenditures — regulated	(57,200		)	(83,613		)
Capital expenditures and other investments — non-regulated	(2,004		)	(876		)
Proceeds from the sale of property, plant and equipment	—			544
Net cash used in investing activities	(59,204		)	(83,945		)
Financing activities:
Proceeds from first mortgage bonds, net	99,786			75,000
Proceeds from notes payable	—			1,431
Long-term debt issuance costs	(924		)	(2,396		)
Proceeds from issuance of common stock net of issuance costs	56,178			2,589
Repayment of First Mortgage Bonds	(50,000		)	—
Redemption of Trust Preferred Securities	(50,000		)	—
Net short-term debt repayments	(10,500		)	(30,000		)
Dividends	(25,464		)	(21,859		)
Other	(750		)	(168		)
Net cash provided by financing activities	18,326			24,597
Net increase in cash and cash equivalents	1,108			637
Cash and cash equivalents at beginning of period	5,620			2,754
Cash and cash equivalents at end of period	$	6,728		$	3,391

See accompanying Notes to Consolidated Financial Statements.

10

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

Note 1 - Summary of Significant Accounting Policies

We operate our businesses as three segments:  electric, gas and other. The Empire District Electric Company (EDE), a Kansas corporation organized in 1909, is an operating public utility engaged in the generation, purchase, transmission, distribution and sale of electricity in parts of Missouri, Kansas, Oklahoma and Arkansas. As part of our electric segment, we also provide water service to three towns in Missouri. The Empire District Gas Company (EDG) is our wholly-owned subsidiary which provides natural gas distribution to communities in northwest, north central and west central Missouri. Our other segment consists of our fiber optics business.

The accompanying interim financial statements do not include all disclosures included in the annual financial statements and therefore should be read in conjunction with the financial statements and notes thereto included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2009.

The information furnished reflects all adjustments, consisting only of normal recurring adjustments, which are in our opinion necessary to state fairly the results for the interim periods as well as present these periods on a consistent basis with the financial statements for the fiscal year ended December 31, 2009, of which there were none.

Note 2 - Recently Issued and Proposed Accounting Standards

Fair Value.In January 2010, the FASB amended the fair value measurements and disclosures guidance to require additional disclosures about fair value measurements. The revised guidance requires new disclosures about the transfers in and out of Level 1 and 2 measurements, including descriptions of the reasons for the transfers. Additionally, the reconciliation of Level 3 measurements now requires separate presentation of sales, issuances and settlements. This guidance for the Level 1 and 2 measurements is effective for periods beginning after December 15, 2009. The guidance on the Level 3 measurements will be effective for periods beginning after December 15, 2010. As this guidance provides only disclosure requirements, the adoption of this standard did not impact our results of operations, cash flows or financial positions.

Consolidation.In June 2009, the FASB amended the accounting guidance for consolidations. This amendment is effective for annual periods beginning after November 15, 2009. The amendment requires an entity to complete a qualitative analysis when determining who must consolidate a variable interest entity (VIE). Additionally, the amendment requires additional disclosures, and an ongoing reassessment of who must consolidate a VIE. A controlling financial interest is required for a VIE and this is evidenced by either a voting interest greater than 50% or a risk and reward model that identifies EDE as the primary beneficiary of a VIE.

Upon adoption of the guidance, we concluded that the consolidation of the Empire District Electric Trust I was appropriate and we reflected it in our consolidated balance sheets in the first quarter of 2010. Subsequently, on June 28, 2010, we redeemed all 2 million outstanding shares of our 8.5% trust preferred securities held by the Trust.

We also evaluated our long-term purchase power agreements to determine if we hold a variable interest. This evaluation identified our purchase power agreement for capacity from Plum Point Energy Station as a variable interest. For this contract we considered operations and maintenance of the power plant to be the most significant activity. In addition, we do not have control over the operation and maintenance of the power plant. Additionally, we have not provided debt or equity investments in the entity, we receive less than the majority of the output of the facility under the contract and do not provide any other financial support through liquidity arrangements, guarantees or other commitments other than the purchase power agreement described in Note 7. Based on the consideration of these factors, we do not consider ourselves to be the primary beneficiary of this VIE. The adoption of this standard did not have a material impact on our financial statements.

11

See Note 1 under “Notes to Consolidated Financial Statements” in our Annual Report on Form 10-K for the year ended December 31, 2009 for further information regarding recently issued accounting standards.

Note 3— Regulatory Matters

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

Regulatory Assets and Liabilities

	June 30, 2010		December 31, 2009
Regulatory Assets:
Under recovered purchased gas costs — gas segment, current	$	201	$	434
Under recovered electric fuel and purchased power costs — current	3,255		338
Regulatory assets, current(1)	$	3,456	$	772
Pension and other postretirement benefits(2)	79,214		81,171
Income taxes	47,962		49,230
Unamortized loss on reacquired debt	12,799		12,167
Unamortized loss on interest rate derivative	1,934		2,091
Asbury five-year maintenance	1,173		1,401
Ice storm costs(3)	9,800		11,673
Deferred Iatan construction accounting costs(4)	5,196		2,732
Asset retirement obligation	3,343		3,264
Under recovered electric fuel and purchased power costs	127		662
Unsettled derivative losses — electric segment	1,524		335
Customer programs	1,430		1,255
System reliability — vegetation management	1,648		1,636
Other	940		637
Regulatory assets, long-term	$	167,090	$	168,254
Total	$	170,546	$	169,026

	June 30, 2010		December 31, 2009
Regulatory Liabilities:
Cost of removal	$	57,790	$	53,083
Income taxes	13,122		20,678
Unamortized gain on interest rate derivative	3,966		4,051
Pension and other postretirement benefits(5)	5,761		6,415
Over recovered electric fuel and purchased power costs(6)	452		1,344
Over recovered purchased gas costs — gas segment	2,718		1,874
Other	88		88
Total	$	83,897	$	87,533

(1) Reflects under recovered costs expected to be recovered within the next 12 months in Missouri rates.

(2) Primarily reflects regulatory assets resulting from the unfunded portion of our pension and OPEB liabilities and regulatory accounting for EDG acquisition costs. Approximately $0.3 million in pension and other postretirement benefit costs have been recognized since January 1, 2010 to reflect the amortization of the regulatory assets that were recorded at the time of the EDG acquisition.

(3) Primarily reflects ice storm costs incurred in 2007 currently being recovered and amortized over a five year period, but also includes deferred wind storm costs of $0.7 million incurred in May 2009, which will be recovered over a five year period commencing in September 2010.

(4) Includes $1.5 million of deferred depreciation costs and $3.7 million in carrying costs related to construction accounting for Iatan 1 recorded since April 19, 2009, in accordance with our regulatory plan. The effect of these deferred carrying charges is reflected in regulated operating expenses, depreciation and in other interest on the statement of operations. Construction accounting, for purposes of the regulatory plan, is specific to Iatan 1 and Iatan 2 construction and allows us to defer certain charges as regulatory assets, including depreciation and carrying costs, related to operation of the facilities until the facilities are ultimately included in our rate base. The amounts deferred, which began at the in-service date for Iatan 1 and will also be deferred for Iatan 2 at its in-service date, will then be amortized over the life of the plants once they are in our rate base.

(5) Includes the effect of costs incurred that are more or less than those allowed in rates for the Missouri (EDE and EDG) and Kansas (EDE) portion of pension costs and the Missouri EDE portion of other postretirement benefit costs. Since

12

January 1, 2010, regulatory liabilities and corresponding expenses have been reduced by approximately $0.2 million as a result of ratemaking treatment.

(6) Primarily consists of Missouri over recovered fuel and purchased power costs for the current accumulation period March 2010 through August 2010.

There have been no changes to regulatory assets and liabilities regarding their rate base inclusion or amortizable lives since December 31, 2009 other than the write off of approximately $1.2 million of tax amortization in the first quarter of 2010 which we estimated rate recovery would no longer be probable for. See Note 12 — Income Taxes for additional information.

Note 4— Risk Management and Derivative Financial Instruments

We engage in hedging activities in an effort to minimize our risk from volatile natural gas prices. We enter into both physical and financial contracts with counterparties relating to our future natural gas requirements that lock in prices (with respect to a range of predetermined percentages of our expected future natural gas needs) in an attempt to lessen the volatility in our fuel expenditures and gain predictability. We recognize that if risk is not timely and adequately balanced or if counterparties fail to perform contractual obligations, actual results could differ materially from intended results.

All derivative instruments are recognized at fair value on the balance sheet with unrealized gains and losses deferred in other comprehensive income (in stockholders’ equity) for effective instruments related to our electric segment, entered into prior to September 1, 2008. All other instruments’ unrealized gains and losses are deferred as a regulatory asset or liability, due to our Missouri fuel recovery mechanism, effective September 1, 2008 for our electric segment, and for our gas segment. For all our derivative contracts, once settled, the realized gain or loss is recorded to fuel expense and subject to our fuel adjustment clause mechanism, which permits the distribution to customers of 95% of the changes in fuel and purchased power costs prudently incurred above or below the base cost.

For those electric instruments entered into prior to September 1, 2008, we record unrealized gains/(losses) on the ineffective portion of our gas hedging activities in “Fuel and purchased power” under the operating revenue deductions section of our Statement of Income 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. Risks and uncertainties affecting the determination of fair value include:  market conditions in the energy industry, especially the effects of price volatility, regulatory and global political environments and requirements, fair value estimations on longer term contracts, the effectiveness of the derivative instrument in hedging the change in fair value of the hedged item, estimating underlying fuel demand and counterparty ability to perform. If we estimate that we have overhedged forecasted demand, the gain or loss on the overhedged portion will be recognized immediately as fuel and purchased power expense in our Consolidated Statement of Income.

As of June 30, 2010 and December 31, 2009, we have recorded the following assets and liabilities representing the fair value of derivative financial instruments, (in thousands):

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ASSET DERIVATIVES		June 30,		December 31,
Derivatives designated as hedging		2010		2009
instruments	Balance Sheet Classification	Fair Value		Fair Value
Natural gas contracts, electric segment	Current assets	$	412	$	2,233
	Non-current assets and deferred charges	680		2,438

Derivatives not designated as hedginginstruments due to regulatory accounting
Natural gas contracts, gas segment	Current assets	7		410
Natural gas contracts, electric segment	Current assets	—		139
	Non-current assets and deferred charges	33		87
Total derivatives assets		$	1,132	$	5,307

LIABILITY DERIVATIVES		June 30,		December 31,
Derivatives designated as hedging		2010		2009
instruments	Balance Sheet Classification	Fair Value		Fair Value
Natural gas contracts, electric segment	Current liabilities	$	4,277	$	4,123

Derivatives not designated as hedging instruments due to regulatory accounting
Natural gas contracts, gas segment	Current liabilities	$	41	$	214
Natural gas contracts, electric segment	Current liabilities	47		—
	Non-current liabilities and deferred credits	1,925		426
Total derivatives liabilities		$	6,290	$	4,763

Electric

A $2.4 million net of tax, unrealized loss representing the fair market value of our electric segment derivative contracts treated as cash flow hedges and entered into prior to September 1, 2008, is recognized as Accumulated Other Comprehensive Income in the capitalization section of the balance sheet as of June 30, 2010. The tax effect of $1.5 million on this loss is included in deferred taxes. These amounts will be adjusted cumulatively on a monthly basis during the determination periods, beginning July 1, 2010 and ending on September 30, 2011. At the end of each determination period, or if cash flow hedge treatment is discontinued, any realized gain or loss for that period related to the instrument is reclassified to fuel expense and is subject to the fuel adjustment clause. As of June 30, 2010, approximately $4.5 million of unrealized losses are applicable to financial instruments which will settle within the next twelve months. The unrealized losses or gains from new cash flow hedges entered into after September 1, 2008, are recorded in regulatory assets or liabilities. This is in accordance with ASC guidance on accounting for regulated operations, given that those regulatory assets and liabilities are probable of recovery through our fuel adjustment mechanism. Unrealized gains and losses from cash flow hedges existing at September 1, 2008 continue to be recorded through comprehensive income.

The following tables set forth the actual pre-tax gains/(losses) and the mark to market effect of unsettled positions from the qualified portion of our hedging activities for the electric segment for each of the periods ended June 30, (in thousands):

Derivatives in Cash Flow	Income Statement Classification of	Amount of Gain / (Loss) Reclassed from OCI into Income(Effective portion)
Hedging Relationships -	Gain / (Loss) on	Three Months Ended						Six Months Ended						Twelve Months Ended
Electric Segment	Derivative	2010			2009			2010			2009			2010			2009
Commodity contracts	Fuel and purchased power expense	$	(950	)	$	(1,739	)	$	(950	)	$	(6,665	)	$	(7,853	)	$	(5,365	)
Total Effective —Electric Segment		$	(950	)	$	(1,739	)	$	(950	)	$	(6,665	)	$	(7,853	)	$	(5,365	)

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Derivatives in Cash Flow Hedging	Statement of	Amount of Gain / (Loss) Recognized in OCI on Derivative(Effective portion)
Relationships -	Comprehensive	Three Months Ended				Six Months Ended						Twelve Months Ended
Electric Segment	Income	2010		2009		2010			2009			2010			2009
Commodity contracts	Fuel and purchased power expense	$	676	$	1,866	$	(5,325	)	$	(7,467	)	$	(7,434	)	$	(58,689	)
Total Effective —Electric Segment		$	676	$	1,866	$	(5,325	)	$	(7,467	)	$	(7,434	)	$	(58,689	)

The ineffective portion of our hedging activities for the electric segment was insignificant for each of the periods ended June 30.

In accordance with the Missouri fuel adjustment clause discussed above, the recoverable portion of any gain or loss is recorded in a regulatory asset or liability account. The following tables set forth “mark-to-market” pre-tax gains/(losses) from derivatives not designated as hedging instruments for the electric segment for each of the periods ended June 30, (in thousands):

Derivatives Not Designated as Hedging Instruments - Due to	Balance Sheet Classification of	Amount of Gain / (Loss) Recognized on Balance Sheet
Regulatory Accounting	Gain / (Loss) on	Three Months Ended						Six Months Ended						Twelve Months Ended
Electric Segment(1)	Derivative	2010			2009			2010			2009			2010			2009
Commodity contracts — electric segment	Regulatory (assets)/liabilities	$	(445	)	$	(74	)	$	(1,737	)	$	(543	)	$	(1,938	)	$	(2,088	)
Total Electric Segment		$	(445	)	$	(74	)	$	(1,737	)	$	(543	)	$	(1.938	)	$	(2,088	)

Derivatives Not Designated as Hedging Instruments - Due to	Statement of Operations Classification of	Amount of Gain / (Loss) Recognized in Income on Derivatives
Regulatory Accounting	Gain / (Loss) on	Three Months Ended						Six Months Ended						Twelve Months Ended
Electric  Segment(1)	Derivative	2010			2009			2010			2009			2010			2009
Commodity contracts	Fuel and purchased power expense	$	(135	)	$	(30	)	$	(397	)	$	(678	)	$	(1,521	)	$	(1,007	)
Total Electric Segment		$	(135	)	$	(30	)	$	(397	)	$	(678	)	$	(1.521	)	$	(1,007	)

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

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

As of July 23, 2010, the following volumes and percentage of our anticipated volume of natural gas usage for our electric operations for the remainder of 2010 and for the next four years are shown below at the following average prices per Dekatherm (Dth).

Dth Hedged

Year	% Hedged		Physical	Financial	Average Price
Remainder 2010	80	%	1,410,000	1,425,000	$	6.380
2011	75	%	3,410,000	2,000,000	$	5.809
2012	40	%	1,665,000	1,420,000	$	7.016
2013	25	%	1,200,000	600,000	$	6.862
2014	8	%	—	620,000	$	6.115

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We utilize the following procurement guidelines for our electric segment, subject to a maximum of 80% of the expected gas usage in any one year (except for the current year):

Year	Minimum % Hedged
Current	Up to 100%
First	60%
Second	40%
Third	20%
Fourth	10%

Gas

We attempt to mitigate our natural gas price risk for our gas segment by a combination of (1) injecting natural gas into storage during the off-heating season months, (2) purchasing physical forward contracts and (3) purchasing financial derivative contracts. We target to have 95% of our storage capacity full by November 1 for the upcoming winter heating season. As the winter progresses, gas is withdrawn from storage to serve our customers. As of June 30, 2010, we had 1.0 million Dths in storage on the three pipelines that serve our customers. This represents 52% of our storage capacity. We have an additional 0.4 million Dths hedged through financial derivative and physical contracts. Our long-term hedge strategy is to mitigate price volatility for our customers by hedging a minimum of 50% of current year, up to 50% of second year and up to 20% of third year expected gas usage by the beginning of the Actual Cost Adjustment (ACA) year at September 1. A Purchased Gas Adjustment (PGA) clause is included in our rates for our gas segment operations, therefore, we mark to market any unrealized gains or losses and any realized gains or losses relating to financial derivative contracts to a regulatory asset or regulatory liability account on our balance sheet.

The following table sets forth “mark-to-market” pre-tax gains / (losses) from derivatives not designated as hedging instruments for the gas segment for each of the periods ended June 30, (in thousands).

Derivatives Not Designated as Hedging Instruments Due to	Balance Sheet Classification of	Amount of Gain / (Loss) Recognized on Balance Sheet
Regulatory Accounting - Gas	Gain / (Loss) on	Three Months Ended					Six Months Ended						Twelve Months Ended
Segment	Derivative	2010			2009		2010			2009			2010			2009
Commodity contracts	Regulatory (assets)/liabilities	$	(52	)	$	77	$	(121	)	$	(1,761	)	$	(142	)	$	(8,210	)
Total - Gas Segment		$	(52	)	$	77	$	(121	)	$	(1,761	)	$	(142	)	$	(8,210	)

Contingent Features

Certain of our derivative instruments contain provisions that require our senior unsecured debt to maintain an investment grade credit rating with any relevant credit rating agency. If our debt were to fall below investment grade, it would be in violation of these provisions, and the counterparties to the derivative instruments could request increased collateralization on derivative instruments in net liability positions. The aggregate fair value of all derivative instruments with the credit-risk-related contingent features that are in a liability position on June 30, 2010 is $3.2 million for which we have posted no collateral in the normal course of business. If the credit-risk-related contingent features underlying these agreements were triggered on June 30, 2010, we would have been required to post $1.2 million of collateral with the counterparty.

Note 5— Fair Value Measurements

The accounting guidance on fair value measurements establishes a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value. These tiers include: (i) Level 1, defined as quoted prices in active markets for identical instruments; (ii) Level 2, defined as inputs

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other than quoted prices in active markets that are either directly or indirectly observable; and (iii) Level 3, defined as unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions. Our Level 3 fair value measurements consist of both quoted price inputs and unobservable quoted inputs provided by a third party.

The guidance also requires that the fair value measurement of assets and liabilities reflect the nonperformance risk of counterparties and the reporting entity, as applicable. Therefore, using credit default spreads, we factored the impact of our own credit standing and the credit standing of our counterparties, as well as any potential credit enhancements (e.g. collateral) into the consideration of nonperformance risk for both derivative assets and liabilities. The results of this analysis were not material to the financial statements.

The following fair value hierarchy table presents information about our assets measured at fair value using the market value approach on a recurring basis as of June 30, 2010 and December 31, 2009.

($ in 000’s)

				Fair Value Measurements at Reporting Date Using
Description	Assets/(Liabilities) at Fair Value			Quoted Prices in Active Markets for Identical Assets (Level 1)			Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	June 30, 2010
Commodity contracts (liabilities)*	$	(5,158	)	$	(5,158	)	$	—	$	—
	December 31, 2009
Commodity contracts assets	$	544		$	544		$	—	$	—

*The only recurring measurements are derivative commodity contracts. Therefore, assets and liabilities are netted together in the table above.

The following tables present the net fair value on a recurring basis using significant unobservable inputs (Level 3) during the periods ended June 30, 2010 and 2009:

Fair Value Measurements Using Significant Unobservable Inputs (Level 3) — 3 Months Ended

	2010		2009
	Derivatives Commodity		Derivatives Commodity
($ in 000’s)	Contracts(1)		Contracts(1)
Beginning Balance, April 1,	$	—	$	3,752
Total gains or (losses) (realized/unrealized)
Included in earnings (or changes in net assets)	—		—
Included in comprehensive income			1,012
Purchases, issuances, and settlements	—		—
Transfers into and (out of) Level 3(2) (3)			(1,232		)
Ending Balance, June 30,	$	—	$	3,532
Changes in unrealized gains relating to assets still held at reporting date	$	—	$	1,012

(1) Net commodity contracts at June 30, 2010 and 2009 included $0.0 million and $3.5 million, respectively, in derivative assets, and no derivative liabilities.

(2) Transferred from Level 3 to Level 1 due to an increase in availability of observable market data and increased market liquidity for these derivatives.

(3) The company’s policy is to recognize transfers in and out of a level as of the end of the period.

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Fair Value Measurements Using Significant Unobservable Inputs (Level 3) — 6 Months Ended

	2010		2009
	Derivatives Commodity		Derivatives Commodity
($ in 000’s)	Contracts(1)		Contracts(1)
Beginning Balance, January 1,	$	—	$	6,208
Total gains or (losses) (realized/unrealized)
Included in earnings (or changes in net assets)	—		—
Included in comprehensive income			(1,444		)
Purchases, issuances, and settlements	—		—
Transfers into and (out of) Level 3(2) (3)			(1,232		)
Ending Balance, June 30,	$	—	$	3,532
Changes in unrealized gains relating to assets still held at reporting date	$	—	$	(1,444	)

(1) Net commodity contracts at June 30, 2010 and 2009 included $0.0 million and $3.5 million, respectively, in derivative assets, and no derivative liabilities.

(2) Transferred from Level 3 to Level 1 due to an increase in availability of observable market data and increased market liquidity for these derivatives.

(3) The company’s policy is to recognize transfers in and out of a level as of the end of the period.

Fair Value Measurements Using Significant Unobservable Inputs (Level 3) — 12 Months Ended

	2010			2009
	Derivatives Commodity			Derivatives Commodity
($ in 000’s)	Contracts(1)			Contracts(1)
Beginning Balance, July 1,	$	3,532		$	22,073
Total gains or (losses) (realized/unrealized)
Included in earnings (or changes in net assets)	—			—
Included in comprehensive income	(295		)	(17,309		)
Purchases, issuances, and settlements	—			—
Transfers into and (out of) Level 3(2) (3)	(3,237		)	(1,232		)
Ending Balance, June 30,	$	—		$	3,532
Changes in unrealized gains relating to assets still held at reporting date	$	(295	)	$	(17,309	)

(1) Net commodity contracts at June 30, 2010 and 2009 included $0.0 million and $3.5 million, respectively, in derivative assets, and no derivative liabilities.

(2) Transferred from Level 3 to Level 1 due to an increase in availability of observable market data and increased market liquidity for these derivatives.

(3) The company’s policy is to recognize transfers in and out of a level as of the end of the period.

Long-Term Debt

The carrying amount of our total debt exclusive of capital leases at June 30, 2010, was $687.5 million compared to a fair market value of approximately $716.3 million. These estimates were based on the quoted market prices for the same or similar issues or on the current rates offered to us for debt of the same remaining maturities. The estimated fair market value may not represent the actual value that could have been realized as of June 30, 2010 or that will be realizable in the future.

Note 6— Financing

On July 26, 2010, we issued a notice to call all $48.3 million aggregate principal amount of our Senior Notes, 7.05% Series due 2022 for redemption on August 27, 2010. We expect to finance the redemption with an offering of first mortgage bonds. The redemption is conditioned upon the consummation of this offering. If we are unable to complete this offering, the notice of redemption would be of no effect unless we waive this condition.

On May 28, 2010, we issued $100 million principal amount of 4.65% first mortgage bonds due June 1, 2020. The net proceeds (after payment of expenses) of approximately $98.9 million were used to redeem all 2 million outstanding shares of our 8.5% trust preferred securities totaling

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$50 million, on June 28, 2010 and to repay short-term debt which was incurred, in part, to fund the repayment, at maturity, of our 6.5% first mortgage bonds due 2010.

On February 25, 2009, we entered into an equity distribution agreement with UBS Securities LLC (UBS). Under the terms of the agreement, as amended, we could offer and sell shares of our common stock, par value $1.00 per share, having an aggregate offering amount of up to $120 million from time to time through UBS, as sales agent. We successfully completed this equity distribution program during the second quarter of 2010 and used the net proceeds to repay short-term debt and for general corporate purposes, including the funding of our current construction program. During the second quarter of 2010, we issued and sold 1,192,644 shares of our common stock pursuant to this equity distribution program, at an average price per share of $18.60, resulting in net proceeds to us of approximately $21.5 million (after payment of approximately $0.7 million in commissions to the sales agent). Since inception of the program, in the aggregate, we issued and sold 6,535,216 shares pursuant to the program, at an average price per share of $18.36, resulting in net proceeds to us of approximately $116.0 million. Sales of the shares pursuant to the equity distribution agreement were made at market prices or as otherwise agreed with UBS.

On July 15, 2005, we entered into a $150 million unsecured revolving credit facility which was scheduled to terminate on July 15, 2010. On March 14, 2006, we entered into the First Amended and Restated Unsecured Credit Agreement which amended and restated 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 reduced over a four year period in line with the amount of construction expenditures we owed for Plum Point Unit 1 and terminated on July 15, 2010.

On January 26, 2010, we entered into the Second Amended and Restated Unsecured Credit Agreement which amended and restated this facility again. This agreement extends the termination date of the revolving credit facility from July 15, 2010 to January 26, 2013. In addition, the pricing and fees under the facility were amended. Interest on borrowings under the facility accrues at a rate equal to, at our option, (i) the highest of (A) the bank’s prime commercial rate, (B) the federal funds effective rate plus 0.5% or (C) one month LIBOR plus 1.0%, plus a margin or (ii) one month, two month or three month LIBOR, in each case, plus a margin. Each margin is based on our current credit ratings and the pricing schedule in the facility. As of the date hereof, and based on our current credit ratings, the LIBOR margin under the facility increased from 0.80% to 2.70%. A facility fee is payable quarterly on the full amount of the commitments under the facility and a usage fee is payable on the full amount of the commitments under the facility for any period in which we have drawn less than 33% of the total revolving commitments under the facility, in each case based on our current credit ratings. In addition, upon entering into the amended and restated facility, we paid an upfront fee to the revolving credit banks of $900,000 in the aggregate. The aggregate amount of the revolving commitments remained unchanged at $150 million and there were no other material changes to the terms of the facility. The facility is used for working capital, general corporate purposes and to back-up our use of commercial paper. This facility requires our total indebtedness 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 for the trailing four fiscal quarters at the end of each fiscal quarter. Failure to maintain these ratios will result in an event of default under the credit facility and will prohibit us from borrowing funds thereunder. As of June 30, 2010, we are in compliance with these ratios. This credit facility is also subject to cross-default if we default on in excess of $10 million in the aggregate on our other indebtedness. This arrangement does not serve to legally restrict the use of our cash in the normal course of operations. There were no outstanding borrowings under this agreement at June 30, 2010. However, $40.0 million was used to back up our outstanding commercial paper.

Note 7— Commitments and Contingencies

We are a party to various claims and legal proceedings arising out of the normal course of our business. Management regularly analyzes this information, and has provided accruals for any

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liabilities, in accordance with the guidelines presented in the ASC on accounting for contingencies. In the opinion of management, it is not probable, given the company’s defenses, that the ultimate outcome of these claims and lawsuits will have a material adverse effect upon our financial condition, or results of operations or cash flows.

On May 22, 2009, a suit was filed in the Circuit Court of Platte County Missouri by several individuals and Class Representatives alleging damages to land, structures, equipment and devastation of crops due to inappropriate management of the levee system around the Iatan Generating Station, of which we are 12% owners. No procedural schedule has been established and we are unable to predict the outcome of the lawsuit.

Coal, Natural Gas and Transportation Contracts

We have entered into long and short-term agreements to purchase coal and natural gas for our energy supply and natural gas operations. Under these contracts, the natural gas supplies are divided into firm physical commitments and derivatives that are used to hedge future purchases. In the event that this gas cannot be used at our plants, the gas would be liquidated at market price. The firm physical gas and transportation commitments are as follows (in millions):

Firm physical gas and transportation contracts

July 1, 2010 through December 31, 2010	$	27.5
January 1, 2011 through December 31, 2012	63.3
January 1, 2013 through December 31, 2014	36.9
January 1, 2015 and beyond	39.2

We have coal supply agreements and transportation contracts in place to provide for the delivery of coal to the plants. These contracts are written with Force Majeure clauses that enable us to reduce tonnages or cease shipments under certain circumstances or events. These include mechanical or electrical maintenance items, acts of God, war or insurrection, strikes, weather and other disrupting events. This reduces the risk we have for not taking the minimum requirements of fuel under the contracts. We entered into a contract in the second quarter of 2010 to transport coal beginning June 30, 2010, which replaced a contract that expired June 29, 2010. The contract term is for six and one-half years and the minimum payments total approximately $91.9 million. The minimum requirements for our coal and coal transportation contracts are as follows (in millions):

Coal and coal transportation contracts

July 1, 2010 through December 31, 2010	$	16.3
January 1, 2011 through December 31, 2012	44.6
January 1, 2013 through December 31, 2014	33.4
January 1, 2015 and beyond	28.0

Purchased Power

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

Our long-term contract with Westar Energy for the purchase of capacity and energy expired on May 31, 2010.

We have a long-term (30 year) agreement for the purchase of capacity from the Plum Point Energy Station, a new 665-megawatt, coal-fired generating facility which is being built by Dynegy near Osceola, Arkansas. Construction began in the spring of 2006 and the target date to meet in-service criteria is August 15, 2010. We have the option to purchase an undivided ownership interest in the 50 megawatts covered by the purchased power agreement in 2015. Commitments under this contract total approximately $48.0 million through August 30, 2015.

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We have a 20-year purchased power agreement which began on December 15, 2008 with Cloud County Windfarm, LLC, owned by Horizon Wind Energy, Houston, Texas to purchase the energy generated at the approximately 105-megawatt Phase 1 Meridian Way Wind Farm located in Cloud County, Kansas which commenced commercial operation on December 15, 2008. We also have a 20-year contract with Elk River Windfarm, LLC, owned by IBERDROLA RENEWABLES, Inc. (formerly known as PPM Energy), to purchase the energy generated at the 150-megawatt Elk River Windfarm located in Butler County, Kansas. Although these agreements are considered operating leases under Generally Accepted Accounting Principles (GAAP), payments for these wind agreements are recorded as purchased power expenses, and, because of the contingent nature of these payments, are not included in our operating lease obligations.

New Construction

On March 14, 2006, we entered into contracts to purchase a 50 megawatt, 7.52%, undivided interest in the Plum Point Energy Station described above. The target date to meet in-service criteria is August 15, 2010. The estimated cost is approximately $88.0 million, excluding allowance for funds used during construction (AFUDC). Our share of the Plum Point costs through June 30, 2010 was $85.9 million.

On June 13, 2006, we announced we had entered into an agreement with Kansas City Power & Light (KCP&L) to purchase an undivided ownership interest in the coal-fired Iatan 2 generating facility. We will own 12%, or approximately 100 megawatts, of the 850-megawatt unit. On January 13, 2010, KCP&L announced that, due to construction delays and unusually cold weather, it was shifting the anticipated in-service date for Iatan 2 from late summer 2010 to the fall of 2010 and commencing a cost and schedule reforecast process as the project enters the startup phase. On April 8, 2010, KCP&L announced the results of the reforecast process. KCP&L currently projects a fourth quarter 2010 in-service date for Iatan 2. Our share of the Iatan 2 construction costs, excluding AFUDC and Empire specific costs, is expected to be in a range of approximately $229 million to $239 million, as compared to the previous estimated range of $218 million to $230 million. Our share of the Iatan 2 costs through June 30, 2010 was $217.8 million.

Recovery of construction costs

We filed a rate increase request with the Missouri Public Service Commission (MPSC) on October 29, 2009 for an annual increase in base rates for our Missouri electric customers in the amount of $68.2 million, or 19.6%. This request was primarily designed to allow us to recover the costs associated with environmental upgrades at Iatan 1 and our investment in new generating units at Iatan 2 and the Plum Point Generating Station. As a result of the delay in the Iatan 2 project, however, we agreed to not seek a permanent increase in the current rate case for any costs associated with the Iatan 2 unit with the exception of that portion of the Iatan common plant needed to operate Iatan 1. A stipulated agreement was filed on May 12, 2010, calling for an annual increase of $46.8 million, provided the Plum Point Generating Station meets its in-service criteria by August 15, 2010. Should the in-service criteria not be met, a base rate increase of $33.1 million is stipulated. The new rates are to be effective September 10, 2010. Both scenarios include incremental additional regulatory amortization in the amount of $10 million that will be recorded as depreciation expense. We have also agreed to the use of construction accounting for our Plum Point project such as we use for our Iatan 1 and Iatan 2 projects. However, construction accounting for Plum Point will not apply for up to 60 days between when Plum Point becomes fully operational and used for service and the date tariffs in this rate case become effective. Construction accounting allows us to defer certain charges as regulatory assets, including depreciation, operating expenses and carrying costs, related to operation of the facilities until the facilities are ultimately included in our rate base. As of the date of this filing, we believe that we have met all but one Plum Point in-service criteria. The remaining test requires that the unit operate at or above 80% of its design load for a continuous 120 hour period with emission equipment operating effectively. Four hours of this test must be above 95% load. We currently estimate that this test will begin on or before August 8, 2010. We anticipate filing a rate case at the conclusion of this case to recover the Iatan 2 costs and Plum Point costs if necessary.

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We also filed a request with the Kansas Corporation Commission (KCC) on November 4, 2009 for an annual increase in base rates for our Kansas electric customers in the amount of $5.2 million, or 24.6%. This request was primarily to allow us to recover capital expenditures associated with our investment in new generating units at Iatan 2 and the Plum Point Generating Station, environmental upgrades at Iatan 1 completed in 2009 and at our Asbury plant completed in 2008, and our Riverton 12 unit that went on line in 2007. A stipulated agreement was filed on May 4, 2010, and approved by the KCC on June 25, 2010, calling for a $2.8 million, or 12.4%, increase in base rates effective July 1, 2010. We will defer depreciation and operating and maintenance expense on both Plum Point and Iatan 2 from their respective in-service dates until the effective date for rates from the next Kansas case, expected to be an abbreviated rate case that will be filed within the next year. These deferrals will be recovered over a 3-5 year period as determined in that next case. We will record AFUDC on all Plum Point and Iatan 2 capital expenditures incurred after January 31, 2010.

On March 25, 2010, we requested a capital cost recovery rider (CCRR) at the Oklahoma Corporation Commission (OCC). The rider is designed to recover the carrying costs on our capital investment for generation, transmission and distribution assets that have been added to the system since our last Oklahoma general rate case (May 2003), as well as investments made on an ongoing basis. As requested, the operation of the CCRR would increase our operating revenue in Oklahoma in a series of three steps to be followed with a general rate case in 2011. If the CCRR is authorized by the OCC, it is expected to result in a maximum overall increase in Oklahoma revenues of approximately $3 million, or approximately 33%.

There are risks that actual costs may exceed budget estimates, delays may occur in obtaining permits and materials, suppliers and contractors may not perform as required under their contracts, there may be inadequate availability, productivity or increased cost of qualified craft labor, start-up activities may take longer than currently planned, the scope and timing of projects may change, the re-baselined schedule may not be met and other events beyond our control, including the failure of one or more of the generation plant co-owners to pay their share of construction, operations and maintenance costs, may occur that may materially affect the schedule, budget, cost and performance of these projects. In addition, costs will be subject to prudency reviews by our regulators.

Leases

We have purchased power agreements with Cloud County Windfarm, LLC and Elk River Windfarm, LLC, which are considered operating leases for GAAP purposes. Details of these arrangements are disclosed in the Purchased Power section of this note.

We also currently have short-term operating leases for one unit train to meet coal delivery demands, for garage and office facilities for our electric segment and for six service center properties for our gas segment. In addition, we have capital leases for certain office equipment and a unit train for our Plum Point generating facility.

Environmental Matters

We are subject to various federal, state, and local laws and regulations with respect to air and water quality and with respect to hazardous and toxic materials and hazardous and other wastes, including their identification, transportation, disposal, record-keeping and reporting, as well as remediation of contaminated sites and other environmental matters. We believe that our operations are in material compliance with present environmental laws and regulations. Environmental requirements have changed frequently and become more stringent over time. We expect this trend to continue. While we are not in a position to accurately estimate compliance costs for any new requirements, we expect them to be material, although recoverable in rates.

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Electric Segment

Air.

The Federal Clean Air Act (CAA) and comparable state laws regulate air emissions from stationary sources such as electric power plants through permitting and/or emission control and related requirements. These requirements include maximum emission limits on our facilities for sulfur dioxide (SO2), particulate matter, and nitrogen oxides (NOx). In the future they are also likely to include limits on emissions of mercury, other hazardous air pollutants (HAPs) and so-called greenhouse gases (GHG) such as carbon dioxide (CO2) and methane.

Permits

Under the CAA we have obtained site operating permits, which are valid for five years, for each of our plants. We received renewed permits for the Asbury, State Line and Energy Center plants in July 2010.

The Prevention of Significant Deterioration (PSD) provisions of the CAA require a permit, and if necessary installation of pollution control equipment, when making a major modification or a change in operation if such modification or change is likely to cause a significant net increase in regulated emissions. In May 2008, KCPL received a Federal grand jury subpoena under the CAA requesting documents relating to capital projects at Iatan 1. We own 12% of Iatan 1. We were informed by KCPL in September 2009 that the US Department of Justice does not intend to bring charges under the CAA in connection with repair work, maintenance or modifications at Iatan Unit 1.

SO2 Emissions

The CAA regulates the amount of SO2 an affected unit can emit through, among other things, a cap and trade program. Each existing affected unit has been allocated a specific number of emission allowances by the U.S. Environmental Protection Agency (EPA), each of which allows the holder to emit one ton of SO2. Covered utilities, such as Empire, must have emission allowances equal to the number of tons of SO2 emitted during a given year by each of their affected units. Allowances in excess of the annual emissions are banked for future use.

In 2009, our SO2 emissions exceeded the annual allocations. This deficit was covered by our banked allowances. When our SO2 allowance bank is exhausted, currently estimated to be mid-2011, we will need to purchase additional SO2 allowances or build a Flue Gas Desulphurization (FGD) scrubber system at our Asbury Plant. Based on current and projected SO2 allowance prices and high-level estimated FGD scrubber construction costs ($115 million in 2010 dollars) and absent other regulatory requirements, it will likely be more economical for us to purchase SO2 allowances than to build a scrubber at the Asbury Plant. If we were to purchase SO2 allowances, we would expect their cost to be fully recoverable in our rates.

NOx Emissions

The CAA regulates the amount of NOx an affected unit can emit. Each of our affected units is in compliance with the NOx limits applicable to it as currently operated.

Ozone, also called ground level smog, is formed by the mixing of NOx and Volatile Organic Compounds in the presence of sunlight. On January 6, 2010, the EPA proposed to lower the primary National Ambient Air Quality Standard (NAAQS) for ozone designed to protect public health and to set a secondary NAAQS for ozone designed to protect sensitive vegetation and ecosystems. The EPA intends to issue final standards by August 31, 2010. Once final standards are set, states will be required to develop State Implementation Plans (SIPs) which reflect these standards.

Clean Air Interstate Rule (CAIR)

In 2005, the EPA promulgated CAIR under the CAA. CAIR generally calls for fossil-fueled power plants greater than 25 megawatts to reduce emission levels of SO2 and NOx in 28 states, including Missouri, where our Asbury, Energy Center, State Line and Iatan Units No. 1 and No. 2

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are located and Arkansas where the Plum Point Energy Station is located. Kansas was not included in CAIR and our Riverton Plant was not affected.

In 2008, the U.S. Court of Appeals for the District of Columbia vacated CAIR and remanded it back to EPA for further consideration, but also stayed its vacatur. As a result, CAIR became effective for NOx on January 1, 2009 and for SO2 on January 1, 2010.

The CAIR requires covered states (including Missouri and Arkansas) to develop SIPs to comply with specific NOx and SO2 state-wide annual budgets. Missouri and Arkansas have approved SIPs and, based on these SIPs, we believe we will have excess NOx allowances for 2010 which will be banked for future use. However, SO2 allowances must be utilized at a 2:1 ratio for our Missouri units as compared to our non-CAIR Kansas units beginning in 2010. As a result, based on current SO2 allowance usage projections, we expect to exhaust our banked allowances by mid-2011 and, as discussed above, will need to purchase additional SO2 allowances or build a scrubber at our Asbury Plant.

In order to meet CAIR requirements, a Selective Catalytic Reduction system (SCR), FGD scrubber system and baghouse were installed at our Iatan 1 plant and an SCR was installed at our Asbury plant in 2008.

On July 6, 2010, the EPA published a proposed CAIR replacement rule entitled the Clean Air Transport Rule (CATR). As proposed, the CATR would include Kansas under the annual and ozone season NOx and the SO2 programs. Missouri would be dropped from the ozone season NOx program while Arkansas would remain in the ozone season NOx program. The beginning date of regulation for the proposed CATR is 2012. The final CATR is expected to be issued by the EPA within 12-14 months. The proposed rule requires a 71% reduction in SO2 from 2005 levels by 2014. We do not expect significant impacts on our operations because of new NOx requirements in CATR. We cannot accurately estimate the cost of any final regulation or predict its precise timing and its impact on our operations at this time. However, absent significant changes to the proposed rule, we expect the final CATR to ultimately require a scrubber and baghouse to be added to our Asbury facility at an estimated cost of $115 million in 2010 dollars and may force retirement of our Riverton coal-fired assets or conversion to natural gas.

Mercury and Electric Steam Generating Unit (EGU) Maximum Achievable Control Technology (MACT)

In 2005, the EPA issued the Clean Air Mercury Rule (CAMR) under the CAA. It set limits on mercury emissions by power plants and created a market-based cap and trade system expected to reduce nationwide mercury emissions in two phases. New mercury emission limits for Phase 1 were to go into effect January 1, 2010. On February 8, 2008, the U.S. Court of Appeals for the District of Columbia vacated CAMR. This decision was appealed to the U.S. Supreme Court which denied the appeal on February 23, 2009.

Based on CAMR, we installed a mercury analyzer at Asbury and installed two mercury analyzers at Riverton in 2008. We continue to operate the mercury analyzers at Riverton and Asbury in accordance with the appropriate state environmental regulator’s guidance.

The EPA issued an Information Collection Rule (ICR) for national emission standards for HAPs, including mercury, for coal and oil-fired electric steam generating units on December 24, 2009. This ICR included our Iatan, Asbury and Riverton plants. We completed the ICR for Asbury and Riverton and submitted them to the EPA on March 31, 2010. KCP&L will complete the Iatan ICR. The EPA ICR is a prelude to development of regulations under Section 112(r) of the CAA maximum achievable emission standards for the control of the emission of HAPs, including mercury. The EPA is under a court order to issue a proposed EGU MACT regulation by March 16, 2011 and to finalize that regulation by November 16, 2011. Absent a successful legal challenge, we expect EGU MACT regulation to ultimately require a scrubber and baghouse to be added to our Asbury facility at an estimated cost of $115 million in 2010 dollars and may force retirement of our Riverton coal-fired assets or conversion to natural gas.

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CO2 Emissions

Our coal and gas plants, vehicles and other facilities, including EDG (our gas segment), emit CO2 and/or other GHGs which are measured in Carbon Dioxide Equivalents (CO2e).

On September 22, 2009, the EPA issued the final Mandatory Reporting of Greenhouse Gases Rule under the CAA which requires power generating and certain other facilities, including EDG that equal or exceed an emission threshold of 25,000 metric tons of CO2e to report GHGs to the EPA annually. The first record keeping year is 2010 with initial reporting due in March 2011. We will report our GHG emissions as required to the EPA in 2011 for EDE. Submission for EDG has been delayed until 2012.

On December 7, 2009, responding to a 2007 US Supreme Court decision that determined that GHGs constitute “air pollutants” under the CAA, the EPA issued its final finding that GHGs threaten both the public health and the public welfare. This “endangerment” finding does not itself trigger any EPA regulations, but is a necessary predicate for the EPA to proceed with regulations to control GHGs. On May 13, 2010, the EPA issued under the CAA its final Prevention of Significant Deterioration and Title V Greenhouse Gas Tailoring Rule to address GHG emissions from stationary sources. The rule, which will be implemented in four steps commencing January 2, 2011, and initially focus on large sources, sets thresholds for GHG emissions that determine when permits will be required under the New Source Review Prevention of Significant Deterioration (PSD) and title V Operating Permit programs applicable to new and existing power plants and other sources. Under the PSD program, required controls for GHG emissions would be determined based on Best Available Control Technology (BACT) for which EPA intends to develop a guidance policy. Several parties have filed petitions with the EPA and lawsuits challenging the EPA’s Endangerment Finding and the Tailoring Rule.

Litigation aimed at controlling GHG emissions has also increased. For example, recently the U.S. Court of Appeals for the Second Circuit has ruled that certain public and private parties can pursue claims that GHG emissions constitute a public nuisance and can seek to recover alleged related damages. However, in March 2010, the full U.S. Court of Appeals for the Fifth Circuit overturned a similar decision by a three-judge panel and will rehear the entire case.

Several proposed pieces of legislation regulating emission of GHGs, including cap and trade systems, are under consideration by Congress with no consensus achieved to date. It is unclear what effect, if any, final federal legislation will have on the EPA’s ability to regulate GHG emissions from stationary sources.

Certain states have taken steps to develop cap and trade programs and/or other regulatory systems which may be more stringent than federal regulations. For example, Kansas is a participating member of the Midwestern Greenhouse Gas Reduction Accord (MGGRA), one purpose of which is to develop a market-based cap and trade mechanism to reduce GHG emissions. The MGGRA has announced, however, that it will not issue a CO2e regulatory system pending federal legislative developments. Missouri is not a participant in the MGGRA.

The ultimate cost of any GHG regulations cannot be determined at this time. However, we would expect the cost of complying with any such regulations to be recoverable in our rates.

Water Discharges

We operate under the Kansas and Missouri Water Pollution Plans that were implemented in response to the Federal Clean Water Act (CWA). Our plants are in material compliance with applicable regulations and have received necessary discharge permits.

The Riverton Plant is affected by regulations for Cooling Water Intake Structures issued by the EPA under the CWA Section 316(b) Phase II. The regulations became final on February 16, 2004. In accordance with these regulations, we submit sampling and summary reports to the Kansas Department of Health and Environment (KDHE) which indicate that the effect of the cooling water intake structure on Empire Lake’s aquatic life is insignificant. In 2007 the United States Court of Appeals for the Second Circuit remanded key sections of these CWA regulations to the EPA. As a result, the EPA suspended the regulations and is expected to revise and re-propose the

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regulations by October 2010. Under the initial regulations, we did not expect costs associated with compliance to be material. We will reassess costs after the proposed revised rules are published.

Ash Ponds.

We own and maintain coal ash ponds located at our Riverton and Asbury Power Plants. Additionally, we own a 12 percent interest in a coal ash pond at the Iatan Generating Station. The EPA has announced its intention to revise its wastewater effluent limitation guidelines under the CWA for coal-fired power plants before 2012. Once the new guidelines are issued, the EPA and states would incorporate the new standards into wastewater discharge permits, including permits for coal ash ponds. We do not have sufficient information regarding the future wastewater effluent discharge guidelines at this time to estimate additional costs that any new standards would impose on our operations. In April and May 2009, we received Information Collection Requests from the EPA regarding our ash ponds, and have responded to such requests. All of the ash ponds are compliant with existing state and federal regulations.

On June 21, 2010, the EPA published in the Federal Register, its proposed new regulation pursuant to the Federal Resource Conservation and Recovery Act (RCRA) governing the management and storage of Coal Combustion Residuals (CCR). In the proposal the EPA presents two options: (1) regulation of CCR under RCRA subtitle C as a hazardous waste and (2) regulation of CCR under RCRA subtitle D as a non-hazardous waste. We are currently performing a study to review all ash management options and associated costs but have not developed specific cost estimates to date. The EPA will accept comments until September 20, 2010. It is anticipated that the final regulation will be published later this year or early in 2011. We expect compliance with the final version of either proposal to result in the need to construct a new landfill and the conversion of existing ash handling from a wet to a dry system(s). We have developed a working preliminary estimated cost of $18 million to comply with either proposal or combination. We expect these costs to be recoverable in our rates. This is a working estimate and we expect the total will change during the study process.

Renewable Energy

We currently purchase more than 15% of our energy through long-term Purchased Power Agreements (PPAs) with Elk River Windfarm, LLC and Cloud County Windfarm, LLC. Through these PPAs, we generate about 900,000 renewable energy certificates (RECs) each year. A REC represents one megawatt-hour of renewable energy that has been delivered into the bulk power grid and “unbundles” the renewable attributes from the associated energy. This unbundling is important because it cannot be determined where the renewable energy is ultimately delivered once it enters the bulk power grid. As a result, RECs provide an avenue for renewable energy tracking and compliance purposes.

On November 4, 2008, Missouri voters approved the Clean Energy Initiative (Proposition C). This initiative requires Empire and other investor-owned utilities in Missouri to generate or purchase electricity from renewable energy sources, such as solar, wind, biomass and hydro power, at the rate of at least 2% of retail sales by 2011, increasing to at least 15% by 2021. In July 2010, the MPSC submitted to the Missouri secretary of state’s office its rule for the renewable energy mandate. We are awaiting action from the Missouri secretary of state but believe we are in compliance with the law. Kansas established a renewable portfolio standard (RPS) in May 2009. Its final rulemaking is expected to be released some time in August 2010. In addition, there are several proposals currently before the U.S. Congress to adopt a nationwide RPS.

We have been selling the majority of our RECs and plan to continue to sell all or a portion of them moving forward. As a result of these REC sales, we cannot claim the underlying energy is renewable. Once a REC has been claimed or retired, it cannot be used for any other purpose. Over time, we expect to retain a sufficient amount of RECs to meet any current or future RPS.

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Gas Segment

The acquisition of our natural gas distribution assets in June 2006 involved the potential future remediation of two former manufactured gas plant (FMGP) sites. FMGP Site #1 in Chillicothe, Missouri is listed in the MDNR Registry of Confirmed Abandoned or Uncontrolled Hazardous Waste Disposal Sites in Missouri. No remediation of this site is expected to be required in the near term. We have received a letter stating no further action is required from the MDNR with respect to FMPG Site #2 in Marshall, Missouri. We have incurred $0.2 million in remediation costs and estimate further remediation costs at these two sites to be minimal.

Note 8 — Retirement Benefits

Net periodic benefit pension cost, some of which is capitalized as a component of labor cost and some of which is deferred as a regulatory asset, is comprised of the following components and is shown for our noncontributory defined benefit pension plan, our supplemental retirement program (SERP) and other postretirement benefits (OPEB) (in thousands):

	Three months ended June 30,
	Pension Benefits						SERP						OPEB
	2010			2009			2010			2009			2010			2009
Service cost	$	1,273		$	1,019		$	17		$	15		$	509		$	509
Interest cost	2,550			2,491			39			37			1,063			1,066
Expected return on plan assets	(2,483		)	(2,601		)	—			—			(966		)	(970		)
Amortization of prior service cost (1)	133			151			(2		)	(2		)	(253		)	(253		)
Amortization of net actuarial loss (1)	1,033			837			32			20			344			356
Net periodic benefit cost	$	2,506		$	1,897		$	86		$	70		$	697		$	708

	Six months ended June 30,
	Pension Benefits						SERP						OPEB
	2010			2009			2010			2009			2010			2009
Service cost	$	2,546		$	2,010		$	34		$	31		$	1,018		$	963
Interest cost	5,100			4,929			79			74			2,125			2,051
Expected return on plan assets	(4,966		)	(5,202		)	—			—			(1,933		)	(1,930		)
Amortization of prior service cost (1)	266			302			(4		)	(4		)	(506		)	(505		)
Amortization of net actuarial loss (1)	2,067			1,591			63			51			689			588
Net periodic benefit cost	$	5,013		$	3,630		$	172		$	152		$	1,393		$	1,167

	Twelve months ended June 30,
	Pension Benefits						SERP						OPEB
	2010			2009			2010			2009			2010			2009
Service cost	$	5,148		$	3,853		$	65		$	64		$	1,885		$	1,800
Interest cost	10,047			9,486			152			147			3,980			3,848
Expected return on plan assets	(10,143		)	(10,573		)	—			—			(3,845		)	(3,804		)
Amortization of prior service cost (1)	568			674			(8		)	(8		)	(1,011		)	(1,011		)
Amortization of net actuarial loss (1)	3,658			2,477			115			123			970			820
Net periodic benefit cost	$	9,278		$	5,917		$	324		$	326		$	1,979		$	1,653

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

Annual contributions to our pension plans are at least equal to the minimum funding requirements of ERISA. Beginning in 2010, we will also be required to fund at least our actuarial cost in accordance with our minimum regulatory agreements. We estimate our 2010 funding to be approximately $12.0 million. The actual minimum funding requirements will be determined based on the results of the actuarial valuations and, in the case of 2011, the performance of our pension assets during 2010. Our OPEB funding policy is to contribute annually an amount at least equal to the actuarial cost of postretirement benefits. We expect to be required to fund approximately $3.2 million in 2010.

See Note 12 — Income Taxes for information regarding the effect of the Patient Protection and Affordable Care Act that was enacted on March 23, 2010.

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Note 9— Stock-Based Awards and Programs

Our performance based restricted stock awards, stock options and their related dividend equivalents are classified as liability awards, in accordance with fair value guidelines. Awards treated as liability instruments are revalued each period until settled, and cost is accrued over the requisite service period and adjusted to fair value at each reporting period until settlement or expiration of the award.

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

	Three Months Ended				Six Months Ended				Twelve Months Ended
	2010		2009		2010		2009		2010		2009
Compensation Expense	$	730	$	669	$	1,528	$	1,248	$	2,572	$	1,712
Tax Benefit Recognized	261		244		549		453		915		607

Activity for our various stock plans for the six months ended June 30, 2010 is summarized below:

Performance-Based Restricted Stock Awards

Performance-based restricted stock awards are 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 fair value of the outstanding restricted stock awards was estimated using a Monte Carlo option valuation model. The assumptions used in the model for each grant year are noted in the following table:

	Fair Value of Grants Outstanding at June 30,
	2010	2009
Risk-free interest rate	0.22% to 0.80%	0.35% to 1.37%
Expected volatility of Empire stock	28.6%	28.8%
Expected volatility of peer group stock	22.4% to 83.0%	21.8% to 79.6%
Expected dividend yield on Empire stock	7.0%	7.3%
Expected forfeiture rates	3%	3%
Plan cycle	3 years	3 years
Fair value percentage	124.0% to 152.0%	105.0% to 130.0%
Weighted average fair value per share	$26.21	$19.29

Non-vested restricted stock awards (based on target number) as of June 30, 2010 and 2009 and changes during the six months ended June 30, 2010 and 2009 were as follows:

	2010				2009
	Number		Weighted Average		Number		Weighted Average
	of shares		Grant Date Price		of shares		Grant Date Price
Nonvested at January 1,	52,200		$	21.57	52,300		$	22.64
Granted	13,000		$	18.36	13,500		$	18.12
Awarded	(15,104	)	$	23.81	(12,394	)	$	22.23
Not Awarded	(2,596	)			(1,206	)
Nonvested at June 30,	47,500		$	19.86	52,200		$	21.57

At June 30, 2010, there was $0.5 million of total unrecognized compensation cost related to estimated outstanding awards. This cost will be recognized over the outstanding years remaining in the vesting period.

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Stock Options

Stock option grants vest upon satisfaction of service conditions. The cost of the awards is generally recognized over the requisite (explicit) service period. The fair value of the outstanding options was estimated as of June 30, 2010 and 2009, under a Black-Scholes methodology. The assumptions used in the valuations are shown below:

	Fair Value of Grants Outstanding at June 30,
	2010	2009
Risk-free interest rate	0.55% to 2.23%	1.25% to 2.97%
Dividend yield	7.0%	7.3%
Expected volatility	24.0%	24.0%
Expected life in months	78	78
Market value	$ 18.77	$ 16.52
Weighted average fair value per option	$   1.05	$   0.63

A summary of option activity under the plan during the six months ended June 30, 2010 and 2009 is presented below:

	2010			2009
		Weighted Average			Weighted Average
	Options	Exercise Price		Options	Exercise Price
Outstanding at January 1,	232,600	$	22.19	205,600	$	22.73
Granted	34,800	$	18.36	27,000	$	18.12
Exercised	—			—
Outstanding at June 30,	267,400	$	21.69	232,600	$	22.19
Exercisable at June 30,	149,200	$	23.04	85,000	$	22.46

The aggregate intrinsic value at June 30, 2010 was less than $0.1 million and at June 30, 2009 was zero. The intrinsic value of the unexercised options is the difference between Empire’s closing stock price on the last day of the quarter and the exercise price multiplied by the number of in the money options had all option holders exercised their option on the last day of the quarter. The intrinsic value is zero if such closing price is less than the exercise price.

The range of exercise prices for the options outstanding at June 30, 2010 was $18.12 to $23.81. The weighted-average remaining contractual life of outstanding options at June 30, 2010 and 2009 was 7.1 years and 7.1 years, respectively. As of June 30, 2010, there was $0.3 million of total unrecognized compensation expense related to the non-vested options and related dividend equivalents granted under the plan. That cost will be recognized over a period of 1 to 3 years.

Employee Stock Purchase Plan

Our Employee Stock Purchase Plan (ESPP) permits the grant to eligible employees of options to purchase common stock at 90% of the lower of market value at date of grant or at date of exercise. The lookback feature of this plan is valued at 90% of the Black-Scholes methodology plus 10% of the maximum subscription price. As of June 30, 2010, there were 331,021 shares available for issuance in this plan.

	2010		2009
Subscriptions outstanding at June 30	72,874		69,830
Maximum subscription price	$	16.06	$	14.62
Shares of stock issued (1)	66,723		44,265
Stock issuance price	$	14.62	$	14.10

(1) Stock will be issued on the closing date of the purchase period, which runs from June 1, 2010 to May 31, 2011.

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

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	ESPP
	2010			2009
Weighted average fair value of grants	$	2.28		$	3.26
Risk-free interest rate	0.35		%	0.48		%
Dividend yield	7.20		%	7.90		%
Expected volatility	17.00		%	40.00		%
Expected life in months	12			12
Grant Date	6/1/10			6/1/09

Note 10- Regulated Operating Expenses

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

	Three Months Ended		Three Months Ended		Six Months Ended		Six Months Ended		Twelve Months Ended		Twelve Months Ended
	2010		2009		2010		2009		2010		2009
Electric transmission and distribution expense	$	3,144	$	2,747	$	5,971	$	5,337	$	11,697	$	10,884
Natural gas transmission and distribution expense	515		548		1,046		1,074		2,133		2,119
Power operation expense (other than fuel)	2,791		3,062		5,695		6,126		11,884		12,369
Customer accounts and assistance expense	2,998		2,736		5,917		5,187		11,326		10,366
Employee pension expense (1)	1,287		1,327		2,751		2,687		5,622		5,457
Employee healthcare plan (1)	1,696		1,375		3,246		2,691		6,463		5,941
General office supplies and expense	2,705		2,564		5,381		4,824		10,626		9,312
Administrative and general expense	3,218		2,851		6,634		5,850		12,995		12,090
Allowance for uncollectible accounts	855		853		1,455		1,800		2,780		3,294
Miscellaneous expense	63		13		93		1		172		102
Total	$	19,272	$	18,076	$	38,189	$	35,577	$	75,698	$	71,934

(1) Does not include capitalized portion of costs, but reflects the GAAP expensed cost plus or minus costs deferred to a regulatory asset or recognized as a regulatory liability for Missouri and Kansas jurisdictions.

Note 11— Segment Information

We operate our business as three segments:  electric, gas and other. As part of our electric segment, we also provide water service to three towns in Missouri. The other segment consists of our fiber optics business.

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

	For the quarter ended June 30, 2010
($-000’s)	Electric		Gas			Other		Eliminations			Total
Statement of Operations Information
Revenues	$	106,686	$	6,516		$	1,428	$	(148	)	$	114,482
Depreciation and amortization	12,373		831			382		—			13,586
Federal and state income taxes	4,497		(219		)	207		—			4,485
Operating income	13,388		543			348		—			14,279
Interest income	61		133			—		(142		)	52
Interest expense	10,147		986			12		(142		)	11,003
Income from AFUDC (debt and equity)	4,337		6			—		—			4,343
Net income	7,405		(372		)	336		—			7,369
Capital Expenditures	$	24,545	$	598		$	608				$	25,751

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	For the quarter ended June 30, 2009
($-000’s)	Electric		Gas			Other		Eliminations			Total
Statement of Operations Information
Revenues	$	103,083	$	7,919		$	1,376	$	(148	)	$	112,230
Depreciation and amortization	11,888		503			348		—			12,739
Federal and state income taxes	4,293		(467		)	221		—			4,047
Operating income	15,500		155			372		—			16,027
Interest income	61		108			—		(108		)	61
Interest expense	10,841		988			13		(108		)	11,734
Income from AFUDC (debt and equity)	3,335		—			—		—			3,335
Net income	8,018		(750		)	359		—			7,627
Capital Expenditures	$	40,673	$	386		$	246				$	41,305

	For the six months ended June 30, 2010
($-000’s)	Electric		Gas		Other		Eliminations			Total
Statement of Operations Information
Revenues	$	220,718	$	31,077	$	2,877	$	(296	)	$	254,376
Depreciation and amortization	24,674		1,339		758		—			26,771
Federal and state income taxes	12,778		1,220		421		—			14,419
Operating income	25,873		3,778		706		—			30,357
Interest income	133		259		—		(270		)	122
Interest expense	20,707		1,969		22		(270		)	22,428
Income from AFUDC (debt and equity)	8,492		6		—		—			8,498
Net income	13,329		1,942		684		—			15,955
Capital Expenditures	$	53,781	$	886	$	1,959				$	56,626

	For the six months ended June 30, 2009
($-000’s)	Electric		Gas		Other		Eliminations			Total
Statement of Operations Information
Revenues	$	209,870	$	36,006	$	2,678	$	(309	)	$	248,245
Depreciation and amortization	23,717		1,003		692		—			25,412
Federal and state income taxes	8,663		576		416		—			9,655
Operating income	31,198		2,769		715		—			34,682
Interest income	136		266		—		(265		)	137
Interest expense	21,400		1,984		40		(265		)	23,159
Income from AFUDC (debt and equity)	6,938		1		—		—			6,939
Net income	16,861		1,003		676		—			18,540
Capital Expenditures	$	80,667	$	855	$	792				$	82,314

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	For the twelve months ended June 30, 2010
($-000’s)	Electric		Gas		Other		Eliminations			Total
Statement of Operations Information
Revenues	$	445,745	$	52,384	$	5,762	$	(592	)	$	503,299
Depreciation and amortization	48,992		2,352		1,509		—			52,853
Federal and state income taxes	22,598		1,216		832		—			24,646
Operating income	63,089		5,643		1,438		—			70,170
Interest income	222		396		—		(416		)	202
Interest expense	42,481		3,943		39		(416		)	46,047
Income from AFUDC (debt and equity)	15,684		7		—		—			15,691
Net income	35,546		1,813		1,352		—			38,711
Capital Expenditures	$	126,589	$	2,287	$	2,430				$	131,306

	For the twelve months ended June 30, 2009
($-000’s)	Electric		Gas		Other		Eliminations			Total
Statement of Operations Information
Revenues	$	448,435	$	65,020	$	5,300	$	(573	)	$	518,182
Depreciation and amortization	48,149		1,982		1,360		—			51,491
Federal and state income taxes	22,472		457		493		—			23,422
Operating income	72,965		4,550		1,294		—			78,809
Interest income	642		393		—		(463		)	572
Interest expense	42,369		3,965		139		(463		)	46,010
Income from AFUDC (debt and equity)	13,970		9		—		—			13,979
Net Income	44,781		873		801		—			46,455
Capital Expenditures	$	180,202	$	2,105	$	1,665				$	183,972

As of June 30, 2010

($-000’s)	Electric		Gas(1)		Other		Eliminations			Total
Balance Sheet Information
Total assets	$	1,797,172	$	135,986	$	23,085	$	(86,550	)	$	1,869,693

(1) Includes goodwill of $39,492.

As of December 31, 2009

($-000’s)	Electric		Gas(1)		Other		Eliminations			Total
Balance Sheet Information
Total assets	$	1,759,415	$	134,355	$	21,907	$	(75,831	)	$	1,839,846

(1) Includes goodwill of $39,492.

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Note 12— Income Taxes

The following table shows our consolidated effective federal and state income tax rates for the applicable periods ended June 30, 2010:

	Three Months Ended		Six-Months Ended		Twelve Months Ended
	2010	2009	2010	2009	2010	2009
Consolidated effective federal and state income tax rates	37.7%	34.7%	47.5%	34.2%	38.9%	33.5%

The effective tax rates for the six months ended June 30, 2010 and the twelve months ended June 30, 2010 are higher than comparable year periods primarily due to the new health care legislation. On March 23, 2010, the Patient Protection and Affordable Care Act became law. This legislation includes a provision that reduces the deductibility, for income tax purposes, of retiree healthcare costs to the extent an employer receives federal subsidies. Companies receive the subsidy when they provide retiree prescription benefits at least equivalent to Medicare Part D coverage in their postretirement healthcare plan. Although the elimination of this tax benefit does not take effect until 2013, this change requires us to recognize the full accounting impact in our financial statements in the period in which the legislation is enacted. As a result, in the first quarter of 2010, we recorded a one-time non-cash charge of approximately $2.1 million to income taxes to reflect the impact of this change. The change in deductibility will increase our effective tax rate slightly during the remainder of 2010. Our 2010 effective tax rate also increased due to the additional tax expense associated with the current year retiree health care accruals.

As part of an agreement reached in our current Missouri electric rate case, we have also agreed to commence an eighteen year amortization of a deferred asset related to the tax benefits of cost of removal. These tax benefits were flowed through to customers from 1981-2008 and totaled approximately $11.1 million. We recorded a regulatory asset expecting to recover these benefits from customers in future periods. We estimated the portion of the amortization period where rate recovery would no longer be probable for this item and wrote off approximately $1.2 million in the first quarter of 2010. Amortization of the remaining regulatory tax asset will begin in 2012, which is also when we expect to be able to request rate recovery of the asset.

We do not expect any significant changes to our unrecognized tax benefits over the next twelve months. The reserve balance related to unrecognized tax benefits as of December 31, 2009 was $906,000 and has not materially changed at June 30, 2010.

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. It provides natural gas distribution to customers in 44 communities in northwest, north central and west central Missouri. Our other segment consists of our fiber optics business. During the twelve months ended June 30 2010, 88.6% of our gross operating revenues were provided from sales from our electric segment (including 0.4% from the sale of water), 10.4% from our gas segment and 1.0% from our other segment.

Earnings

During the second quarter of 2010, basic and diluted earnings per weighted average share of common stock were $0.18 as compared to $0.22 in the second quarter of 2009. For the six

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months ended June 30, 2010, basic and diluted earnings per weighted average share of common stock were $0.40 as compared to $0.54 for the six months ended June 30, 2009. For the twelve months ended June 30, 2010, basic earnings per weighted average share of common stock were $1.03 as compared to $1.37 for the twelve months ended June 30, 2009 and diluted earnings per weighted average share of common stock were $1.03 as compared to $1.36 for the twelve months ended June 30, 2009. The primary negative drivers for all three periods presented were increased electric operations and maintenance expenses and the dilutive effect of additional shares of common stock issued. Also negatively impacting both the six months and  twelve months ended June 30, 2010 were the two non-cash charges in the first quarter of 2010 discussed below. The primary positive driver for both the second quarter of 2010 and the six months ended June 30, 2010 was increased electric revenues resulting from increased demand in the both the first and second quarters of 2010 resulting from favorable weather. Increased AFUDC favorably impacted all three periods presented.

The table below sets forth a reconciliation of basic and diluted earnings per share between the three months, six months and twelve months ended June 30, 2009 and June 30, 2010, which is a non-GAAP presentation. The economic substance behind our non-GAAP earning per share (EPS) measure is to present the after tax impact of significant items and components of the statement of income on a per share basis before the impact of additional stock issuances.

We believe this presentation is useful to investors because the statement of income does not readily show the EPS impact of the various components, including the effect of new stock issuances. This could limit the readers’ understanding of the reasons for the EPS change from the previous year’s EPS. This information is useful to management, and we believe this information is useful to investors, to better understand the reasons for the fluctuation in EPS between the prior and current years on a per share basis.

This reconciliation may not be comparable to other companies or more useful than the GAAP presentation included in the statement of income. We also note that this presentation does not purport to be an alternative to earnings per share determined in accordance with GAAP as a measure of operating performance or any other measure of financial performance presented in accordance with GAAP. Management compensates for the limitations of using non-GAAP financial measures by using them to supplement GAAP results to provide a more complete understanding of the factors and trends affecting the business than GAAP results alone.

	Three Months Ended			Six Months Ended			Twelve Months Ended
Earnings Per Share — June 30, 2009	$	0.22		$	0.54		$	1.37
Revenues
Electric on-system	$	0.02		$	0.11		$	(0.01	)
Electric off-system and other	0.05			0.09			(0.05		)
Gas	(0.03		)	(0.09		)	(0.24		)
Other	0.00			0.00			0.01
Expenses
Electric fuel and purchased power	(0.05		)	(0.12		)	0.00
Cost of natural gas sold and transported	0.04			0.12			0.26
Regulated — electric segment	(0.03		)	(0.06		)	(0.08		)
Regulated —gas segment	0.01			0.01			0.01
Other segment	0.00			0.00			0.00
Maintenance and repairs	(0.01		)	(0.01		)	(0.02		)
Depreciation and amortization	(0.02		)	(0.03		)	(0.03		)
Other taxes	0.00			(0.01		)	(0.01		)
Interest charges	0.01			0.01			0.00
AFUDC	0.02			0.03			0.03
Change in effective income tax rates	(0.01		)	(0.02		)	0.00
Med-D and cost of removal non-cash charges	0.00			(0.09		)	(0.09		)
Other income and deductions	(0.01		)	(0.02		)	(0.03		)
Dilutive effect of additional shares issued	(0.03		)	(0.06		)	(0.09		)
Earnings Per Share — June 30, 2010	$	0.18		$	0.40		$	1.03

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Recent Activities

Financings

On May 28, 2010, we issued $100 million principal amount of 4.65% first mortgage bonds due June 1, 2020. The net proceeds (after payment of expenses) of approximately $98.9 million, were used to redeem all 2 million outstanding shares of our 8.5% trust preferred securities totaling $50 million, on June 28, 2010 and to repay short-term debt which was incurred, in part, to fund the repayment, at maturity, of our 6.5% first mortgage bonds due 2010.

We successfully completed our equity distribution program during the second quarter of 2010 and used the net proceeds to repay short-term debt and for general corporate purposes, including the funding of our current construction program. During the second quarter of 2010, we issued and sold 1,192,644 shares of our common stock pursuant to this equity distribution program, at an average price per share of $18.60, resulting in net proceeds to us of approximately $21.5 million (after payment of approximately $0.7 million in commissions to the sales agent). Since inception of the program, in the aggregate, we issued and sold 6,535,216 shares pursuant to the program, at an average price per share of $18.36, resulting in net proceeds to us of approximately $116.0 million.

On July 26, 2010, we issued a notice to call all $48.3 million aggregate principal amount of our Senior Notes, 7.05% Series due 2022 for redemption on August 27, 2010. We expect to finance the redemption with an offering of first mortgage bonds. The redemption is conditioned upon the consummation of this offering. If we are unable to complete this offering, the notice of redemption would be of no effect unless we waive this condition.

Iatan 2 Coal Investment Tax Credits

A December 2009 award from an arbitration panel ordered KCP&L to renegotiate with the IRS a previous $125 million advanced coal investment tax credit granted its Iatan 2 plant. The arbitration panel agreed that we should have received our 12% share of the credit as 12% owners of Iatan 2. The arbitration panel ruled that if the IRS did not grant us our 12% share of the credit, worth approximately $17.7 million, then KCP&L must pay us the difference. The tax credit will have no significant income statement impact as the credit, which will reduce our tax payments, will flow to our customers over the life of the plant. On May 17, 2010, KCP&L filed a motion in the Circuit Court of Platte County, Missouri to vacate in part the arbitration award on the grounds that the arbitration panel exceeded its authority. We filed a motion to dismiss on the grounds that the court lacks jurisdiction over this suit. On July 7, 2010, we received an IRS-approved memorandum of understanding (MOU) between us and the IRS. Both we and KCP&L have executed revised MOUs that await execution by the IRS. KCP&L’s challenges to the arbitration ruling remain pending in both State and Federal court.

Regulatory Matters

A stipulated agreement in our current Missouri electric rate case was filed on May 12, 2010, calling for an annual increase of $46.8 million, provided the Plum Point Generating Station meets its in-service criteria by August 15, 2010. Should the in-service criteria not be met, a base rate increase of $33.1 million is stipulated. The new rates are to be effective September 10, 2010. Both scenarios include incremental additional regulatory amortization in the amount of $10 million that will be recorded as depreciation expense. As of the date of this filing, we believe that we have met all but one Plum Point in-service criteria. The remaining test requires that the unit operate at or above 80% of its design load for a continuous 120 hour period with emission equipment operating effectively. Four hours of this test must be above 95% load. We currently estimate that this test will begin on or before August 8, 2010. We anticipate filing a rate case at the conclusion of this case to recover the Plum Point costs if necessary.

As a result of the delay in the Iatan 2 project, we have also agreed not to seek a permanent increase in the current rate case for any costs associated with the Iatan 2 unit with the exception of that portion of the Iatan common plant needed to operate Iatan 1. We anticipate filing a rate case at

35

the conclusion of this case to recover the Iatan 2 costs. We have also agreed to the use of construction accounting for our Plum Point project such as we use for our Iatan 1 and Iatan 2 projects. However, construction accounting for Plum Point will not apply for up to 60 days between when Plum Point becomes fully operational and used for service and the date tariffs in this rate case become effective. Construction accounting allows us to defer certain charges as regulatory assets, including depreciation, operating expenses and carrying costs related to operation of the facilities until the facilities are ultimately included in our rate base. See Note 7 of “Notes to Consolidated Financial Statements.”

A stipulated agreement in our current Kansas rate case was filed on May 4, 2010, and approved by the KCC on June 25, 2010, calling for a $2.8 million, or 12.4%, increase in base rates effective July 1, 2010. We will defer depreciation and operating and maintenance expense on both Plum Point and Iatan 2 from their respective in-service dates until the effective date for rates from the next Kansas case, expected to be an abbreviated rate case that will be filed within the next year. These deferrals will be recovered over a 3-5 year period as determined in that next case. We will record AFUDC on all Plum Point and Iatan 2 capital expenditures incurred after January 31, 2010.

On March 25, 2010, we requested a capital cost recovery rider (CCRR) at the Oklahoma Corporation Commission (OCC). The rider is designed to recover the carrying costs on our capital investment for generation, transmission and distribution assets that have been added to the system since our last Oklahoma general rate case (May 2003), as well as investments made on an ongoing basis. As requested, the operation of the CCRR would increase our operating revenue in Oklahoma in a series of three steps to be followed with a general rate case in 2011. If the CCRR is authorized by the OCC, it is expected to result in a maximum overall increase in Oklahoma revenues of approximately $3 million, or approximately 33%.

On March 12, 2010, we filed Generation Formula Rate (GFR) tariffs with the FERC which we propose to be utilized for our wholesale customers. On May 28, 2010, the FERC issued an order that conditionally approved our GFR filing subject to refund effective June 1, 2010. On June 30, 2010, three of our on-system wholesale customers were granted intervention in the GFR rate case. Also on May 28, 2010, we filed a notice with the FERC requesting termination of the current bundled service agreements for our wholesale customers effective July 31, 2010. On July 28, 2010, the FERC issued an order accepting and suspending the proposed terminations for a nominal period to become effective July 31, 2010, subject to refund. The FERC’s order also consolidated the GFR and termination proceedings.

On February 24, 2010, the MPSC unanimously approved an agreement among the Office of the Public Counsel (OPC), the MPSC staff and us for an increase of $2.6 million in base rates for our Missouri gas customers. Pursuant to the agreement, new rates went into effect on April 1, 2010.

On June 1, 2010, we advised the Arkansas Public Service Commission of the intention to file an application for a general change or modification in our rates, charges and tariffs no sooner than 60 days and no later than 90 days from the date of notice.

For additional information, see “Rate Matters” below.

Shareholder Rights Plan

Our shareholder rights plan, dated as of July 26, 2000, expired July 25, 2010, pursuant to its terms.

Ozark Beach Plant

Our hydroelectric generating plant (FERC Project No. 2221), located on the White River at Ozark Beach, Missouri, has a generating capacity of 16 megawatts. We have a long-term license from FERC to operate this plant which forms Lake Taneycomo in southwestern Missouri. As part of the Energy and Water Development Appropriations Act of 2006 (the Appropriations Act), a new minimum flow was established with the intent of increasing minimum flows on recreational streams in Arkansas. To accomplish this, the level of Bull Shoals Lake will be increased an average of 5 feet. The increase at Bull Shoals will decrease the head waters available for generation at Ozark Beach by 5 feet and, thus, reduce our electrical output. We estimate the lost production to be up to 16% of

36

our average annual energy production for this unit. The loss in this facility would require us to replace it with additional generation from our gas-fired and coal-fired units or with purchased power. The Appropriations Act requires the Southwest Power Administration (SWPA), in coordination with us and our relevant public service commissions, to determine our economic detriment.

The SWPA published its Final Determination Report on January 23, 2009 documenting the procedure they intended to use to calculate the present value of the future lifetime replacement cost of the electrical energy and capacity lost due to the White River Minimum Flows project at Ozark Beach. The actual hydropower compensation values were to be calculated using the method presented in the Final Determination and current values for the specified parameters based on the official implementation date. Assuming a January 1, 2011 date of implementation for the White River Minimum Flows project and November 2008 values for the specified parameters, the SWPA’s determination at that time resulted in a present value for the estimated future lifetime replacement costs of the electrical energy and capacity at Ozark Beach of $41.3 million. On June 8, 2009, the SWPA published a draft addendum to its January 2009 Final Determination Report documenting proposed changes to the SWPA’s methodology, including the inclusion of an additional discount rate source to be used by the SWPA in determination of the present value of the losses. Assuming a January 1, 2011 date of implementation for the White River Minimum Flows project and current values for the specified parameters, the SWPA’s Draft Addendum to its Final Determination results in a present value of $22.3 million for the estimated future lifetime replacement costs of the electrical energy and capacity at Ozark Beach. We and the MPSC have provided comments on the new methodology included in the draft addendum but cannot predict the final outcome. Originally, the Appropriations Act had a provision for the Army Corp of Engineers to provide a one time payment to us for lost energy production. This provision was revised in October 2009 to allow the SWPA to pay for damages through a special disbursement account. Under the revised law, payments must be made annually by the SWPA in an amount of at least $5 million until the total damages are reimbursed. On June 17, 2010, the SWPA posted a revised Final Determination that our customers’ damages were $26.5 million. We understand that the SWPA intends to make a payment of at least $5 million by September 30, 2010. This will have no material impact on net income as the benefits will be flowed through to our customers.

Renewable Energy

On November 4, 2008, Missouri voters approved the Clean Energy Initiative (Proposition C). This initiative requires Empire and other investor-owned utilities in Missouri to generate or purchase electricity from renewable energy sources, such as solar, wind, biomass and hydro power, at the rate of at least 2% of retail sales by 2011, increasing to at least 15% by 2021. In July 2010, the MPSC submitted to the Missouri secretary of state’s office its rule for the renewable energy mandate. We are awaiting action from the Missouri secretary of state but believe we are in compliance with the law. Kansas established a renewable portfolio standard (RPS) in May 2009. Its final rulemaking is expected to be released some time in August 2010. In addition, there are several proposals currently before the U.S. Congress to adopt a nationwide RPS.

Healthcare Reform Act - Medicare Part D benefits

On March 23, 2010, the Patient Protection and Affordable Care Act was enacted. This legislation includes a provision that reduces the deductibility, for income tax purposes, of retiree healthcare costs to the extent an employer receives federal subsidies. Companies receive the subsidy when they provide retiree prescription benefits at least equivalent to Medicare Part D coverage in their postretirement healthcare plan. Although the elimination of this tax benefit does not take effect until 2013, this change requires us to recognize the full accounting impact in our financial statements in the period in which the legislation is enacted. As a result, in the first quarter of 2010, we recorded a one-time non-cash charge of approximately $2.1 million to reflect the impact of this change. Our 2010 effective tax rate also increased due to the additional tax expense associated with the current year retiree health care accruals. See Note 12 of “Notes to Consolidated Financial Statements.”

37

RESULTS OF OPERATIONS

The following discussion analyzes significant changes in the results of operations for the three-month, six-month and twelve-month periods ended June 30, 2010, compared to the same periods ended June 30, 2009.

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

	Quarter Ended						Six Months Ended				Twelve Months Ended
	2010			2009			2010		2009		2010		2009
Electric	$	7.4		$	8.0		$	13.3	$	16.8	$	35.5	$	44.8
Gas	(0.4		)	(0.8		)	2.0		1.0		1.8		0.9
Other	0.4			0.4			0.7		0.7		1.4		0.8
Net income	$	7.4		$	7.6		$	16.0	$	18.5	$	38.7	$	46.5

*Differences could occur due to rounding.

Electric Segment

Overview

Our electric segment income for the second quarter of 2010 was $7.4 million as compared to $8.0 million for the second quarter of 2009.

Electric operating revenues comprised approximately 92.8% of our total operating revenues during the second quarter of 2010. Of our total electric operating revenues during the second quarter of 2010, approximately 38.0% were from residential customers, 32.7% from commercial customers, 16.1% from industrial customers, 4.3% from wholesale on-system customers, 4.8% from wholesale off-system transactions, 2.6% from other electric revenues, primarily public authorities, and 1.5% from miscellaneous sources. The percentage of revenues provided from our wholesale off-system transactions increased during the second quarter of 2010 as compared to the second quarter of 2009, primarily due to increased market demand resulting from the warmer weather in May and June of 2010.

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 and for off-system sales for the applicable periods ended June 30, were as follows:

	kWh Sales
	(in millions)
	Second	Second			6 Months	6 Months			12 Months	12 Months
	Quarter	Quarter	%		Ended	Ended	%		Ended	Ended	%
Customer Class	2010	2009	Change*		2010	2009	Change*		2010	2009	Change*
Residential	396.3	387.2	2.4	%	1,035.6	938.1	10.4	%	1,963.9	1,915.9	2.5	%
Commercial	405.6	403.9	0.4		791.3	779.9	1.5		1,591.2	1,630.5	(2.4	)
Industrial	259.4	252.0	2.9		490.4	492.3	(0.4	)	990.3	1,034.0	(4.2	)
Wholesale on-system	85.4	82.7	3.2		170.3	163.5	4.2		338.9	339.0	(0.1	)
Other**	29.5	29.8	(1.0	)	63.3	62.0	2.2		124.8	123.7	0.8
Total on-system sales	1,176.2	1,155.6	1.8		2,550.9	2,435.8	4.7		5,009.1	5,043.1	(0.7	)
Off-system	213.3	111.9	90.7		395.8	245.7	61.1		666.0	624.1	6.7
Total KWh Sales	1,389.5	1,267.5	9.6		2,946.7	2,681.5	9.9		5,675.1	5,667.2	0.1

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

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

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	Electric Segment Operating Revenues
	($ in millions)
	Second		Second				6 Months		6 Months				12 Months		12 Months
	Quarter		Quarter		%		Ended		Ended		%		Ended		Ended		%
Customer Class	2010		2009		Change*		2010		2009		Change*		2010		2009		Change*
Residential	$	40.4	$	39.5	2.3	%	$	94.4	$	88.1	7.2	%	$	186.7	$	182.4	2.4	%
Commercial	34.8		35.3		(1.3	)	64.5		64.9		(0.6	)	135.4		138.2		(2.0	)
Industrial	17.1		16.8		1.8		31.2		31.7		(1.6	)	65.5		67.6		(3.1	)
Wholesale on-system	4.5		4.3		5.0		9.5		9.0		5.1		18.7		18.7		(0.5	)
Other**	2.8		2.7		1.0		5.6		5.5		2.4		11.7		11.4		3.1
Total on-system revenues	$	99.6	$	98.6	1.0		$	205.2	$	199.2	3.0		$	418.0	$	418.3	(0.1	)
Off-system	5.1		2.6		94.5		11.3		6.6		71.8		19.1		21.5		(11.2	)
Total revenues from kWh sales	104.7		101.2		3.4		216.5		205.8		5.2		437.1		439.8		(0.6	)
Miscellaneous revenues***	1.6		1.4		10.5		3.3		3.2		3.4		6.9		6.9		0.5
Total electric operating revenues	$	106.3	$	102.6	3.5		$	219.8	$	209.0	5.2		$	444.0	$	446.7	(0.6	)
Water revenues	0.4		0.5		0.4		0.9		0.9		1.2		1.7		1.7		0.5
Total electric segment operating revenues	$	106.7	$	103.1	3.5		$	220.7	$	209.9	5.2		$	445.7	$	448.4	(0.6	)

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

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

***Miscellaneous revenues include transmission service revenue, late payment fees, renewable energy credit sales, rent, etc.

Quarter Ended June 30, 2010 Compared to Quarter Ended June 30, 2009

On-System Operating Revenues and Kilowatt-Hour Sales

KWh sales for our on-system customers increased during the second quarter of 2010 as compared to the second quarter of 2009 primarily due to favorable weather and customer growth. Revenues for our on-system customers increased approximately $1.0 million, or 1.0%, primarily due to favorable weather in the second quarter of 2010. Weather and other related factors increased revenues by an estimated $0.8 million compared to last year’s second quarter. Total cooling degree days (the cumulative number of degrees that the average temperature for each day during that period was above 65° F) for the second quarter of 2010 were 29.7% more than the same period last year and 51.2% more than the 30-year average, mainly due to unseasonably hot weather in May and June of 2010. Customer growth contributed an estimated $0.5 million of the increase in revenues. Our electric customer growth for the twelve months ended June 30, 2010 was 0.5%. Rate changes had a negative effect of an estimated $0.3 million during the second quarter of 2010.

Residential kWh sales and related revenues increased during the second quarter of 2010 due to the favorable weather and increased customer growth.

Commercial kWh sales increased during the second quarter of 2010 due to the favorable weather and increased customer growth, while the related revenues decreased.

Industrial kWh sales and revenues increased during the second quarter of 2010 as compared to the second quarter of 2009.

On-system wholesale kWh sales and revenues increased during the second quarter of 2010 as compared to the same period in 2009 reflecting the warmer weather in May and June of 2010.

Off-System Electric Transactions

In addition to sales to our own customers, we also sell power to other utilities as available, including through the Southwest Power Pool (SPP) energy imbalance services (EIS) market. See “— Competition” below. The majority of our off-system sales margins are now included as a component of the fuel adjustment clause in our Missouri, Kansas and Oklahoma jurisdictions and generally adjust the fuel and purchased power expense. As a result, nearly all of the off-system sales margin flows back to the customer and has little effect on income.

Off-system revenues and related expenses were more during the second quarter of 2010 as compared to the second quarter of 2009 primarily due to increased market demand resulting from

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the warmer weather in May and June of 2010. Total purchased power related expenses are included in our discussion of purchased power costs below.

Miscellaneous Revenues

Our miscellaneous revenues were $1.6 million for the second quarter of 2010 as compared to $1.4 million in the second quarter of 2009. These revenues are comprised mainly of transmission revenues, late payment fees and renewable energy credit sales.

Operating Revenue Deductions

During the second quarter of 2010, total electric segment operating expenses increased approximately $5.7 million (6.5%) compared with the same period last year.

Total fuel and purchased power expenses increased approximately $2.7 million (6.5%) during the second quarter of 2010. The table below is a reconciliation of our actual fuel and purchased power expenditures (netted with the regulatory adjustments) to the fuel and purchased power expense shown on our statement of income for the second quarter of 2010 and 2009.

(in millions)	2010			2009
Actual fuel and purchased power expenditures	$	44.8		$	38.7
Kansas regulatory adjustments*	—			0.1
Missouri fuel adjustment deferral*	(0.7		)	2.6
Missouri fuel adjustment recovery**	—			0.1
Unrealized loss on derivatives	0.1			—
Total fuel and purchased power expense per income statement	$	44.2		$	41.5

*A negative amount indicates costs have been under recovered from customers and a positive amount indicates costs have been over recovered from customers.

**Currently being recovered from customers from prior accumulation periods.

The overall fuel and purchased power increase reflects increased generation by both our gas fired and coal fired units and a decrease in purchased power volume that was offset by an increase in purchased power prices in the second quarter of 2010 as compared to 2009. The increase in fuel costs includes the effect of increased market demand resulting from warmer weather in the second quarter of 2010 and increased off-system sales.

Summarized in the table below are our estimated cost and volume changes in the components of fuel and purchased power expenses for the second quarter of 2010 as compared to the second quarter of 2009. This table incorporates all the changes mentioned above. As shown below, the largest impact on fuel and purchased power costs was increased generation by our gas-fired units.

(in millions)	Three Months Ended June 30, 2010 vs. 2009
Natural gas generation volume	$	9.8
Coal generation volume	0.3
Purchased power spot purchase volume	(1.1		)
Purchased power (cost per mWh)	2.3
Natural gas (cost per mWh)	(4.7		)
Coal (cost per mWh)	(0.4		)
Other (primarily fuel adjustments)	(3.5		)
TOTAL	$	2.7

Regulated operating expenses increased approximately $1.5 million (9.4%) during the second quarter of 2010 as compared to the same period in 2009 primarily due to increases of $0.4 million in transmission and distribution expense, $0.3 million in professional services, $0.3 million in employee health care expense, $0.2 million in employee pension expense, $0.2 million in other power supply expense, $0.2 million in customer accounts expense (mainly increased banking fees),

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$0.1 million in general labor costs and $0.1 million in director, stockholder and other investor expense. These increases were partially offset by $0.3 million in other steam power expense related to Iatan 1 operating costs that we were able to defer in accordance with our agreement with the MPSC that allows deferral of certain costs until the environmental upgrades to Iatan 1 are included in our rate base.

Maintenance and repairs expense increased approximately $0.7 million (7.9%) in the second quarter of 2010 as compared to 2009 primarily due to increases of $0.5 million in maintenance and repairs expense at the Riverton plant due to the 5-year maintenance outage which began on March 20, 2010 and ended May 21, 2010, $0.3 million in maintenance and repairs expense at the Asbury plant mainly due to a maintenance outage in May 2010, $0.3 million in distribution maintenance, and $0.2 million in maintenance and repairs expense at the Iatan plant. These increases were partially offset by a $0.7 million decrease in maintenance and repairs expense at the State Line Combined Cycle (SLCC) Plant.

Depreciation and amortization expense increased approximately $0.5 million (4.1%) during the quarter primarily reflecting our additions to plant in service. This includes the construction accounting effect of deferring $0.3 million of Iatan 1 depreciation expense. Other taxes increased approximately $0.1 million during the second quarter of 2010 due to increased property tax reflecting our additions to plant in service and increased municipal franchise taxes.

Six Months Ended June 30, 2010 Compared to Six Months Ended June 30, 2009

On-System Operating Revenues and Kilowatt-Hour Sales

KWh sales for our on-system customers increased during the six months ended June 30, 2010 as compared to the six months ended June 30, 2009 primarily due to colder weather in the first quarter of 2010 and warmer weather in the second quarter of 2010 as compared to the same periods in 2009. Revenues for our on-system customers increased approximately $6.0 million, or 3.0%. Weather and other related factors increased revenues by an estimated $7.6 million during the six months ended June 30, 2010 compared to the six months ended June 30, 2009. Customer growth contributed an estimated $0.9 million to revenues while rate changes had a negative effect of an estimated $2.5 million during the six months ended June 30, 2010.

The increase in residential kWh sales and revenues during the six months ended June 30, 2010 was primarily due to the weather conditions and customer growth discussed above.

Commercial kWh sales increased during the six months ended June 30, 2010 due to the favorable weather and increased customer growth, while the related revenues decreased.

Industrial kWh sales and revenues decreased mainly due to a slowdown continuing in the first quarter of 2010 created by economic uncertainty.

On-system wholesale kWh sales increased 4.2% and revenues increased 5.1% during the six months ended June 30, 2010 reflecting the weather conditions discussed above.

Off-System Electric Transactions

Off-system revenues and related expenses were more during the six months ended June 30, 2010 as compared to the same period in 2009 primarily due to increased market demand resulting from the warmer weather in May and June of 2010 and colder weather in the first quarter of 2010. Total purchased power related expenses are included in our discussion of purchased power costs below.

Miscellaneous Revenues

Our miscellaneous revenues were $3.3 million for the six months ended June 30, 2010 as compared to $3.2 million during the same period in 2009. These revenues are comprised mainly of transmission revenues, late payment fees and renewable energy credit sales.

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Operating Revenue Deductions

During the six months ended June 30, 2010, total electric segment operating expenses increased approximately $16.2 million (9.1%) compared with the same period last year.

Total fuel and purchased power expenses increased approximately $6.6 million (7.5%) during the six months ended June 30, 2010. The table below is a reconciliation of our actual fuel and purchased power expenditures (netted with the regulatory adjustments) to the fuel and purchased power expense shown on our statement of operations for the six months ended June 30, 2010 and 2009.

(in millions)	2010			2009
Actual fuel and purchased power expenditures	$	98.0		$	88.4
Kansas regulatory adjustments*	(0.4		)	0.4
Missouri fuel adjustment deferral*	(2.6		)	(0.5		)
Missouri fuel adjustment recovery**	(0.5		)	0.1
Unrealized loss on derivatives	0.4			—
Total fuel and purchased power expense per income statement	$	94.9		$	88.4

*A negative amount indicates costs have been under recovered from customers and a positive amount indicates costs have been over recovered from customers.

**Currently being refunded to customers from prior accumulation periods.

The overall fuel and purchased power increase reflects increased market demand resulting from the warmer weather in May and June of 2010 and colder weather in the first quarter of 2010 as compared to the prior year periods.

Summarized in the table below are our estimated cost and volume changes in the components of fuel and purchased power expenses for the six months ended June 30, 2010 as compared to the six months ended June 30, 2009. This table incorporates all the changes mentioned above. As shown below, the largest impact on fuel and purchased power costs was increased generation by our gas-fired units.

(in millions)	Six Months Ended June 30, 2010 vs. 2009
Natural gas generation volume	$	15.7
Coal generation volume	2.3
Purchased power spot purchase volume	(3.5		)
Purchased power (cost per mWh)	2.8
Natural gas (cost per mWh)	(7.1		)
Coal (cost per mWh)	(0.5		)
Other (primarily fuel adjustments)	(3.1		)
TOTAL	$	6.6

Regulated operating expenses for our electric segment increased approximately $3.1 million (10.0%) during the six months ended June 30, 2010 as compared to the same period in 2009 primarily due to increases of $0.6 million in transmission and distribution expense, $0.5 million in employee health care expense, $0.5 million in customer accounts expenses (mainly increased banking fees), $0.4 million in general labor costs, $0.3 million in employee pension expense, $0.2 million in property insurance, $0.2 million in professional services, $0.1 million in injuries and damages, $0.1 million in general office expense, $0.1 million in other power operation expense, $0.1 million in customer assistance expense, $0.1 million in director, stockholder and other investor expense and $0.1 million in research and development expense. These increases were partially offset by $0.6 million in other steam power expense related to Iatan 1 operating costs that we were able to defer in accordance with our agreement with the MPSC that allows deferral of certain costs until the environmental upgrades to Iatan 1 are included in our rate base.

Maintenance and repairs expense increased approximately $0.8 million (4.7%) during the six months ended June 30, 2010 as compared to 2009 primarily due to increases of $0.9 million in maintenance and repairs expense at the Riverton plant due to the 2010 5-year maintenance outage, $0.4 million in maintenance and repairs expense at the Asbury plant mainly due to a maintenance

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outage in May 2010, $0.4 million in distribution maintenance, $0.3 million in maintenance and repairs expense at the Iatan plant and $0.2 million in transmission maintenance. These increases were almost entirely offset by a $1.5 million decrease in maintenance and repairs expense at the SLCC plant as compared to 2009 when there was a maintenance outage at the plant in the first quarter.

Depreciation and amortization expense increased approximately $1.0 million (4.0%) during the six months ended June 30, 2010 primarily reflecting our additions to plant in service. This includes the construction accounting effect of deferring $0.7 million of Iatan 1 depreciation expense. Other taxes increased approximately $0.6 million during the six months ended June 30, 2010 due to increased property tax reflecting our additions to plant in service and increased municipal franchise taxes.

Twelve Months Ended June 30, 2010 Compared to Twelve Months Ended June 30, 2009

On-System Operating Revenues and Kilowatt-Hour Sales

For the twelve months ended June 30, 2010, kWh sales to our on-system customers decreased 0.7% with the associated revenues decreasing approximately $0.3 million (0.1%). Weather and other related factors decreased revenues an estimated $6.1 million. Rate changes, primarily the August 2008 Missouri rate increase (discussed below), contributed an estimated $4.8 million to revenues while continued customer growth contributed an estimated $1.0 million. The increase in residential kWh sales and revenues during the twelve months ended June 30, 2010 was primarily due to colder weather in the first quarter of 2010 and warmer weather in the second quarter of 2010 while the increase in residential revenues was also due to the 2008 Missouri rate increase. Industrial and commercial kWh sales and revenues decreased during the twelve months ended June 30, 2010, mainly due to general economic conditions. On-system wholesale kWh sales and revenues decreased slightly during the twelve months ended June 30, 2010 reflecting the general economic conditions.

Off-System Electric Transactions

Off-system revenues decreased $2.4 million during the twelve months ended June 30, 2010 as compared to the same period in 2009 primarily due to decreased market demand and lower gas prices in the third and fourth quarters of 2009. Total purchased power related expenses are included in our discussion of purchased power costs below.

Miscellaneous Revenues

Our miscellaneous revenues were $6.9 million for both the twelve months ended June 30, 2010 and the twelve months ended June 30, 2009. These revenues are comprised mainly of transmission revenues, late payment fees and renewable energy credit sales.

Operating Revenue Deductions

During the twelve months ended June 30, 2010, total electric segment operating expenses increased approximately $7.2 million (1.9%) compared to the prior period.

Total fuel and purchased power expenses increased approximately $0.1 million (0.1%) during the twelve months ended June 30, 2010. The table below is a reconciliation of our actual fuel and purchased power expenditures (netted with the regulatory adjustments) to the fuel and purchased power expense shown on our statement of income for the twelve months ended June 30, 2010 and 2009.

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(in millions)	2010			2009
Actual fuel and purchased power expenditures	$	191.7		$	188.1
Kansas regulatory adjustments*	(0.2		)	0.3
Missouri fuel adjustment deferral*	(4.0		)	(0.3		)
Missouri fuel adjustment recovery**	1.0			0.1
Unrealized loss on derivatives	0.1			0.3
Total fuel and purchased power expense per income statement	$	188.6		$	188.5

*A negative amount indicates costs have been under recovered from customers and a positive amount indicates costs have been over recovered from customers.

**Currently being recovered from customers from prior accumulation periods.

The overall fuel and purchased power increase includes the effect of decreased market demand resulting from mild weather in the third and fourth quarters of 2009 offset by increased demand in the first and second quarters of 2010 due to favorable weather conditions.

Summarized in the table below are our estimated cost and volume changes in the components of fuel and purchased power expenses for the twelve months ended June 30, 2010 as compared to the twelve months ended June 30, 2009. This table incorporates all the changes mentioned above. As shown below, the increases in fuel costs were offset by decreases in volume and in fuel adjustments.

(in millions)	Twelve Months Ended June 30, 2010 vs. 2009
Coal generation volume	$	3.2
Natural gas generation volume	(2.5		)
Purchased power spot purchase volume	(2.1		)
Natural gas (cost per mWh)	3.3
Purchased power (cost per mWh)	1.3
Coal (cost per mWh)	0.4
Other (primarily fuel adjustments)	(3.5		)
TOTAL	$	0.1

Regulated operating expenses increased approximately $4.3 million (6.9%) during the twelve months ended June 30, 2010 as compared to the same period in 2009 primarily due to increases of $1.2 million in professional services, $1.1 million in general labor costs, $0.8 million in transmission and distribution expense, $0.7 million in customer accounts expense (mainly increased banking fees), $0.5 million in employee health care expense, $0.4 million in employee pension expense, $0.4 million in other steam power expense at the Iatan 1 plant, $0.2 million in other steam power expense at the Asbury plant, $0.3 million in property insurance, $0.2 million in employee welfare costs, $0.2 million in other power operation expense, $0.1 million in research and development expense and $0.1 million in director, stockholder and other investor expense. These increases were partially offset by $1.2 million in other steam power expense related to Iatan 1 operating costs that we were able to defer in accordance with our agreement with the MPSC that allows deferral of certain costs until the environmental upgrades to Iatan 1 are included in our rate base. Decreases of $0.7 million in injuries and damages and $0.1 million in regulatory commission expense also decreased expenses.

Maintenance and repairs expense increased approximately $1.0 million (3.1%) during the twelve months ended June 30, 2010 as compared to 2009 primarily due to increases of $1.6 million in transmission and distribution maintenance (including $0.6 million of ice storm-related amortization), $1.0 million in maintenance and repairs expense at the Asbury plant mainly due to a maintenance outage in May 2010, $0.6 million in maintenance and repairs expense at the Riverton plant due to the 2010 5-year maintenance outage, $0.1 million in maintenance and repairs expense at the Ozark Beach plant and $0.2 million in repairs expense to the Riverton gas units. These increases were partially offset by decreases of $2.1 million in maintenance and repairs expense to the SLCC which experienced a maintenance outage in the first quarter of 2009 and $0.4 million in

44

maintenance and repairs expense at the Iatan 1 plant, which experienced an outage in the fourth quarter of 2008.

Depreciation and amortization expense increased approximately $0.8 million (1.8%) during the twelve months ended June 30, 2010 reflecting our additions to plant in service. This includes the construction accounting effect of deferring $1.3 million of Iatan 1 depreciation expense. Other taxes increased approximately $0.9 million during the twelve months ended June 30, 2010 due to increased property tax reflecting our additions to plant in service and increased municipal franchise taxes.

Gas Segment

Gas Operating Revenues and Sales

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

Total Gas Delivered to Customers

	Three Months Ended		%		Six months ended		%		Twelve months ended		%
(bcf sales)	2010	2009	change		2010	2009	Change		2010	2009	change
Residential	0.19	0.29	(32.9	)%	1.71	1.60	6.6	%	2.79	2.70	3.5	%
Commercial	0.12	0.15	(22.9	)	0.77	0.72	7.0		1.33	1.28	3.8
Industrial*	0.02	0.02	1.9		0.06	0.17	(64.6	)	0.11	0.52	(79.1	)
Other**	0.00	0.00	(51.6	)	0.02	0.02	25.0		0.04	0.03	13.5
Total retail sales	0.33	0.46	(28.5	)	2.56	2.51	2.1		4.27	4.53	(5.8	)
Transportation sales	1.09	0.92	17.6		2.69	2.08	29.2		4.93	3.94	25.4
Total gas operating sales	1.42	1.38	2.2		5.25	4.59	14.4		9.20	8.47	8.7

Operating Revenues and Cost of Gas Sold

	Three Months Ended						Six months ended						Twelve months ended
($ in millions)	2010		2009		% change		2010		2009		% change		2010		2009		% change
Residential	$	3.9	$	4.9	(20.6	)%	$	20.1	$	23.0	(12.4	)%	$	33.3	$	39.5	(15.6	)%
Commercial	1.6		2.1		(25.6	)	8.1		9.5		(14.6	)	14.2		17.3		(18.1	)
Industrial*	0.1		0.2		(41.3	)	0.5		1.6		(71.8	)	0.9		4.9		(81.3	)
Other**	0.0		0.0		(41.7	)	0.3		0.3		(1.3	)	0.4		0.4		(10.4	)
Total retail revenues	$	5.6	$	7.2	(22.8	)	$	29.0	$	34.4	(15.7	)	$	48.8	$	62.1	(21.5	)
Other revenues	0.1		0.0		189.3		0.2		0.1		65.9		0.3		0.2		38.2
Transportation revenues*	0.8		0.7		22.2		1.9		1.5		24.7		3.3		2.7		23.0
Total gas operating revenues	$	6.5	$	7.9	(17.7	)	$	31.1	$	36.0	(13.7	)	$	52.4	$	65.0	(19.4	)
Cost of gas sold	2.3		4.2		(46.2	)	17.4		23.5		(26.1	)	29.5		43.1		(31.7	)
Gas operating revenues over cost of gas in rates	$	4.2	$	3.7	14.6		$	13.7	$	12.5	9.7		$	22.9	$	21.9	4.8

*Percentage change for six months ended and twelve  months ended reflects the transfer of a customer from transportation to industrial sales in April 2008 and back to transportation in April 2009 and a customer switching from industrial sales to transportation in October 2009 after an eight-month suspension.

**Other includes other public authorities and interdepartmental usage.

Quarter Ended June 30, 2010 Compared to Quarter Ended June 30, 2009

Operating Revenues and bcf Sales

Gas retail sales decreased during the second quarter of 2010 as compared to 2009 primarily due to warmer weather in the second quarter of 2010. Gas sales are less during the summer months as the heating season runs from November to March of each year. Residential and commercial sales decreased during the second quarter of 2010 as compared to the second quarter of 2009 primarily due to the weather. Heating degree days were 35.3% lower in the second quarter of 2010 as compared to the second quarter of 2009 and 35.0% lower than the 30-year average mainly due to unseasonably warm weather in April of 2010. Industrial sales, which are not as

45

weather sensitive, increased slightly during the second quarter of 2010 as compared to the same period in 2009.

During the second quarter of 2010, gas segment revenues were approximately $6.5 million as compared to $7.9 million in the second quarter of 2009 despite a rate increase of $2.6 million that went into effect on April 1, 2010 (see “Rate Matters” below). Our PGA revenue (which represents the cost of gas recovered from our customers) was approximately $2.3 million as compared to $4.2 million in the second quarter of 2009, a decrease of approximately $1.9 million. This decrease was largely driven by the decreases in the PGAs that went into effect May 15, 2009 and November 13, 2009. Total retail sales decreased 28.5% while the corresponding revenues decreased only 22.8%. This was due to the April 2010 rate change that caused a greater allocation of margin to be shifted into the customer charge and less to sales volumes.

Our PGA clause allows us to recover from our customers, subject to routine regulatory review, the cost of purchased gas supplies, transportation and storage, including costs associated with the use of financial instruments to hedge the purchase price of natural gas. Pursuant to the provisions of the PGA clause, the difference between actual costs incurred and costs recovered through the application of the PGA are reflected as a regulatory asset or regulatory liability until the balance is recovered from or credited to customers. As of June 30, 2010, we had under recovered purchased gas costs of $0.2 million recorded as a regulatory asset and over recovered purchased gas costs of $2.7 million recorded as a regulatory liability.

Operating Revenue Deductions

Total other operating expenses were approximately $2.3 million during the second quarter of 2010 as compared to $2.6 million in the first quarter of 2009, a decrease of $0.3 million. This decrease was mainly due to a $0.2 million decrease in employee pension expense and a $0.1 million decrease in director, stockholder and other investor expense.

Our gas segment had a net loss of $0.4 million for the second quarter of 2010 as compared to a net loss of $0.8 million for the second quarter of 2009.

Six Months Ended June 30, 2010 Compared to Six Months Ended June 30, 2009

Operating Revenues and bcf Sales

Gas retail sales increased during the six months ended June 30, 2010 as compared to the same period in 2009 mainly due to colder weather in the first quarter of 2010. Residential and commercial sales increased during the six months ended June 30, 2010 as compared to the same period in 2009 primarily due to the colder weather. Industrial sales decreased during the six months ended June 30, 2010 as compared to the same period in 2009 mainly due to the switching of customers between industrial sales and transportation and the suspension of operations of a large volume sales customer (see footnote above).

During the six months ended June 30, 2010, gas segment revenues were approximately $31.1 million as compared to $36.0 million in the six months ended June 30, 2009, a decrease of $4.9 million. This decrease was largely driven by the PGAs that went into effect May 15, 2009 and November 13, 2009. During the six months ended June 30, 2010, our PGA revenue was approximately $17.4 million as compared to $23.5 million during the six months ended June 30, 2009, a decrease of approximately $6.1 million.

Operating Revenue Deductions

Total other operating expenses were $5.0 million for the six months ended June 30, 2010 as compared to $5.4 million for the six months ended June 30, 2009. This decrease was mainly due to a $0.2 million decrease in employee pension expense and a $0.2 million decrease in customer accounts expense, primarily bad debt expense.

Our gas segment had net income of $1.9 million for the six months ended June 30, 2010 as compared to $1.0 million for the six months ended June 30, 2009.

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Twelve Months Ended June 30, 2010 Compared to Twelve Months Ended June 30, 2009

Operating Revenues and bcf Sales

Gas retail sales decreased during the twelve months ended June 30, 2010 mainly due to the switching of customers between industrial sales and transportation, the suspension of operations of a large volume sales customer (see footnote above), and the effect of our gas segment customer contraction of 0.7% for the twelve months ended June 30, 2010. We believe this contraction was due to depressed economic conditions. We estimate that the rate of gas customer contraction will level out during the next three years and begin modest growth after 2012. Residential and commercial sales increased during the twelve months ended June 30, 2010 primarily due to colder weather in the first quarter of 2010.

During the twelve months ended June 30, 2010, gas segment revenues were approximately $52.4 million as compared to $65.0 million in the twelve months ended June 30, 2009, a decrease of $12.6 million. This decrease was largely driven by a decrease in the PGAs that went into effect May 15, 2009 and November 13, 2009. During the twelve months ended June 30, 2010, our PGA revenue was approximately $29.5 million as compared to $43.1 million during the twelve months ended June 30, 2009, a decrease of approximately $13.7 million.

Operating Revenue Deductions

Total other operating expenses were $9.8 million for the twelve months ended June 30, 2010 as compared to $10.4 million for the twelve months ended June 30, 2009. This decrease was mainly due to a $0.3 million decrease in customer accounts expense, primarily bad debt expense and a $0.3 million decrease in employee pension expense.

Our gas segment had net income of $1.8 million for the twelve months ended June 30, 2010 as compared to $0.9 million for the twelve months ended June 30, 2009.

Consolidated Company

Income Taxes

The following table shows the increases in our consolidated provision for income taxes (in millions) for the applicable periods ended June 30, 2010 as compared to 2009:

	Three Months Ended	Six-Months Ended	Twelve Months Ended
Consolidated provision for income taxes	$0.4	$4.8	$0.7

The following table shows our consolidated effective federal and state income tax rates for the applicable periods ended June 30, 2010:

	Three Months Ended		Six Months Ended		Twelve Months Ended
	2010	2009	2010	2009	2010	2009
Consolidated effective federal and state income tax rates	37.7%	34.7%	47.5%	34.2%	38.9%	33.5%

The effective tax rates for the six months ended June 30, 2010 and the twelve months ended June 30, 2010 are higher than comparable year periods primarily due to the new health care legislation. On March 23, 2010, the Patient Protection and Affordable Care Act became law. This legislation includes a provision that reduces the deductibility, for income tax purposes, of retiree healthcare costs to the extent an employer receives federal subsidies. Companies receive the subsidy when they provide retiree prescription benefits at least equivalent to Medicare Part D coverage in their postretirement healthcare plan. Although the elimination of this tax benefit does not take effect until 2013, this change requires us to recognize the full accounting impact in our financial statements in the period in which the legislation is enacted. As a result, in the first quarter of 2010, we recorded a one-time non-cash charge of approximately $2.1 million to income taxes to

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reflect the impact of this change. Our 2010 effective tax rate also increased due to the additional tax expense associated with the current year retiree health care accruals.

As part of an agreement reached in our current Missouri electric rate case, we have also agreed to commence an eighteen year amortization of a deferred asset related to the tax benefits of cost of removal. These tax benefits were flowed through to customers from 1981-2008 and totaled approximately $11.1 million. We recorded a regulatory asset expecting to recover these benefits from customers in future periods. We estimated the portion of the amortization period where rate recovery would no longer be probable for this item and wrote off approximately $1.2 million in the first quarter of 2010. Amortization of the remaining regulatory tax asset will begin in 2012, which is also when we expect to be able to request rate recovery of the asset.

Nonoperating Items

The following table shows the total allowance for funds used during construction (AFUDC) for the applicable periods ended June 30. AFUDC increased during all three periods in 2010 as compared to the same periods in 2009 due to higher levels of construction in each period.

	Three Months Ended				Six Months Ended				Twelve Months Ended
($ in millions)	2010		2009		2010		2009		2010		2009
Allowance for equity funds used during construction	$	1.9	$	1.2	$	3.7	$	2.6	$	7.2	$	6.0
Allowance for borrowed funds used during construction	2.4		2.1		4.8		4.3		8.5		8.0
Total AFUDC	$	4.3	$	3.3	$	8.5	$	6.9	$	15.7	$	14.0

Total interest charges on long-term and short-term debt for the applicable periods ended June 30, are shown below. The decrease in long-term debt interest for the quarter ended June 30, 2010 reflects the redemption of 6½% first mortgage bonds on April 1, 2010 which were replaced by 4.65% first mortgage bonds issued May 28, 2010. The increases in long-term debt interest for the six-month ended and twelve-month ended periods reflect the interest on the $100 million principal amount of first mortgage bonds we issued May 28, 2010 and the interest on the $75 million principal amount of first mortgage bonds we issued March 27, 2009. The decreases in short-term debt interest for the six-month ended and twelve-month ended periods primarily reflect lower levels of borrowing.

	Interest Charges
	(in millions)
	Second		Second				6 Months		6 Months				12 Months		12 Months
	Quarter		Quarter		%		Ended		Ended		%		Ended		Ended		%
	2010		2009		Change*		2010		2009		Change*		2010		2009		Change*
Long-term debt interest	10.1		10.9		(7.6	)%	20.6		20.5		0.1	%	42.1		39.7		6.1	%
Short-term debt interest	0.2		0.2		18.6		0.5		0.8		(37.7	)	0.8		1.8		(53.9	)
Trust preferred securities interest	1.0		1.1		(3.3	)	2.1		2.1		(1.7	)	4.2		4.2		(0.8	)
Iatan1 carrying charges	(0.6	)	(0.6	)	(3.6	)	(1.2	)	(0.6	)	92.3		(1.9	)	(0.6	)	210.7
Other interest	0.3		0.1		42.5		0.4		0.3		46.5		0.8		0.9		(10.2	)
Total interest charges	11.0		11.7		(6.2	)	22.4		23.1		(3.2	)	46.0		46.0		0.1

*Beginning in the second quarter of 2009, we deferred Iatan 1 carrying charges in accordance with our agreement with the MPSC that allows deferral of certain costs until the environmental upgrades to Iatan 1 are included in our rate base.

RATE MATTERS

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

Our rates for retail electric and natural gas services (other than specially negotiated retail rates for industrial or large commercial customers, which are subject to regulatory review and approval) are determined on a “cost of service” basis. Rates are designed to provide, after recovery of allowable operating expenses, an opportunity for us to earn a reasonable return on “rate base.” “Rate base” is generally determined by reference to the original cost (net of accumulated

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depreciation and regulatory amortization) of utility plant in service, subject to various adjustments for deferred taxes and other items. Over time, rate base is increased by additions to utility plant in service and reduced by depreciation, regulatory amortization and retirement of utility plant and write-off’s as ordered by the utility commissions. In general, a request of new rates is made on the basis of a “rate base” as of a date prior to the date of the request and allowable operating expenses for a 12-month test period ended prior to the date of the request. Although the current rate making process provides recovery of some future changes in rate base and operating costs, it does not reflect all changes in costs for the period in which new retail rates will be in place. This results in a lag between the time we incur costs and the time when we can start recovering the costs through rates. See Note 3 of “Notes to Consolidated Financial Statements” for the amounts recorded for regulatory amortization.

The following table sets forth information regarding rate increases since January 1, 2008:

Jurisdiction	Date Requested	Annual Increase Granted		Percent Increase Granted	Date Effective
Kansas – Electric	November 4, 2009	$	2,800,000	12.4%	July 1, 2010
Missouri – Gas	June 5, 2009	$	2,600,000	4.37%	April 1, 2010
Missouri – Electric	October 1, 2007	$	22,040,395	6.70%	August 23, 2008

Electric Segment

Missouri

2009 Rate Case

On October 29, 2009, we filed a request with the MPSC for an annual increase in base rates for our Missouri electric customers in the amount of $68.2 million, or 19.6%. This request was primarily designed to allow us to recover capital expenditures associated with environmental upgrades at Iatan 1 and our investment in new generating units at Iatan 2 and the Plum Point Generating Station. As a result of the delay in the Iatan 2 project, however, we agreed to not seek a permanent increase in the current rate case for any costs associated with the Iatan 2 unit with the exception of that portion of the Iatan common plant needed to operate Iatan 1. We anticipate filing a rate case at the conclusion of this case to recover the Iatan 2 costs.

A stipulated agreement was filed on May 12, 2010, calling for an annual increase of $46.8 million, provided the Plum Point Generating Station meets its in-service criteria by August 15, 2010. Should the in-service criteria not be met, a base rate increase of $33.1 million is stipulated. The new rates are to be effective September 10, 2010. Both scenarios include incremental additional regulatory amortization in the amount of $10 million that will be recorded as depreciation expense. As of the date of this filing, we believe that we have met all but one Plum Point in-service criteria. The remaining test requires that the unit operate at or above 80% of its design load for a continuous 120 hour period with emission equipment operating effectively. Four hours of this test must be above 95% load. We currently estimate that this test will begin on or before August 8, 2010. We anticipate filing a rate case at the conclusion of this case to recover the Plum Point costs if necessary. See Note 7 of “Notes to Consolidated Financial Statements.” We have also agreed to the use of construction accounting for our Plum Point project such as we use for our Iatan 2 project. However, construction accounting for Plum Point will not apply for up to 60 days between when Plum Point becomes fully operational and used for service and the date tariffs in this rate case become effective. Construction accounting allows us to defer certain charges as regulatory assets, including depreciation and carrying costs, related to operation of the facilities until the facilities are ultimately included in our rate base. We have also agreed to commence an eighteen year amortization of a deferred asset related to the tax benefits of cost of removal. These tax benefits were flowed through to customers from 1981 to 2008 and totaled approximately $11.1 million. We had previously recorded a regulatory asset expecting to recover these benefits from customers in future periods. We estimated the portion of the amortization period where rate recovery would no longer be probable for this item and wrote off approximately $1.2 million in the first quarter of 2010.

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Amortization of the remaining regulatory tax asset will begin in 2012, which is also when we expect to be able to request rate recovery of the asset. See Note 12 of “Notes to Consolidated Financial Statements”.

2007 Rate Case

The MPSC issued an order on July 30, 2008 in response to a request filed with the MPSC on October 1, 2007 for an annual increase in base rates for our Missouri electric customers. This order granted an annual increase in revenues for our Missouri electric customers in the amount of $22.0 million, or 6.7%, based on a 10.8% return on equity. The new rates went into effect August 23, 2008.

The order contains two components. The first component provides an addition to base rates of approximately $27.7 million. This increase in base rates was partially offset by a $5.7 million reduction to regulatory amortization, which is the second component to support certain credit metrics of the overall change in revenue authorized by the MPSC. Regulatory amortization provides us additional cash through rates during the current construction cycle. This construction, which is part of our long-range plan to ensure reliability, includes the facilities at the Riverton Power Plant and Iatan 2 Power Plant, as well as environmental improvements at the Asbury Power Plant and at Iatan 1. The regulatory amortization is now approximately $4.5 million annually and is recorded as depreciation expense.

The MPSC also authorized a fuel adjustment clause for our Missouri customers effective September 1, 2008. The MPSC established a base cost for the recovery of fuel and purchased power expenses used to supply energy. The clause permits the distribution to customers of 95% of the changes in fuel and purchased power costs above or below the base cost. Off-system sales margins are also part of the recovery of fuel and purchased power costs. As a result, the off-system sales margin flows back to the customer. Rates related to the recovery of fuel and purchased power costs will be modified twice a year subject to the review and approval by the MPSC. In accordance with accounting guidance for regulated activities, 95% of the difference between the actual cost of fuel and purchased power and the base cost of fuel and purchased power recovered from our customers is recorded as an adjustment to fuel and purchased power expense with a corresponding regulatory asset or a regulatory liability. If the actual fuel and purchased power costs are higher or lower than the base fuel and purchased power costs billed to customers, 95% of these amounts will be recovered or refunded to our customers when the fuel adjustment clause is modified. On April 1, 2009, we filed proposed rate schedules with the MPSC requesting an increase of $1.9 million in revenues for the under recovered fuel costs recognized for the six month period ended February 28, 2009. This increase in revenue was approved by the MPSC on May 21, 2009, became effective June 1, 2009 and is billed through our fuel adjustment clause. On October 1, 2009, we filed proposed rate schedules with the MPSC requesting a decrease of $0.8 million in revenues for the over recovered fuel and purchased power costs recognized for the six month period ended August 31, 2009.

The MPSC order in the rate case approved a Stipulation and Agreement providing for the recovery of deferred expenses of approximately $14.2 million over a five year period for the 2007 ice storms. In addition, the MPSC order required the implementation of a two-way tracking mechanism for recovery of the costs relating to the new MPSC rules on infrastructure inspection and vegetation management. The mechanism authorized by the MPSC creates a regulatory liability in any year we spend less than the target amount, which has been set at $8.6 million for our Missouri jurisdiction, and a regulatory asset if we spend more than the target amount. Any regulatory asset and liability amounts created using the tracking mechanism will then be netted against each other and taken into account in our next rate case. The MPSC also approved Stipulations and Agreements providing for the continuation of the pension and other post-retirement employee benefits tracking mechanism established in our 2006 and 2007 Missouri rate orders.

The MPSC issued its Report and Order on July 30, 2008, effective August 9, 2008. The OPC and intervenors Praxair, Inc. and Explorer Pipeline Company filed applications for rehearing with the MPSC regarding this order. On August 12, 2008, the MPSC issued its Order Granting Expedited Treatment and Approving Compliance Tariff Sheets, effective August 23, 2008, in which the MPSC

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approved our tariff sheets containing our base rates for service rendered on and after August 23, 2008, and approved our fuel adjustment clause tariff sheets effective September 1, 2008. On September 3, 2008, the MPSC denied all pending applications for rehearing.

On October 2, 2008, the OPC and intervenors Praxair, Inc. and Explorer Pipeline Company filed Petitions for Writ of Review with the Cole County Circuit Court. These actions were consolidated into one proceeding, briefs were filed and the Cole County Circuit Court heard oral arguments on September 29, 2009. The Cole County Circuit Court issued a ruling on December 31, 2009, affirming the Commission’s Report and Order. OPC, Praxair and Explorer Pipeline have filed appeals with the Western District Court of Appeals.

2006 Rate Case

In December 2008, the OPC and intervenors Praxair, Inc. and Explorer Pipeline Company filed Petitions for Writ of Review with the Cole County Circuit Court. These actions were consolidated into one proceeding, briefs were filed and the Cole County Circuit Court heard oral arguments on June 2, 2009. The Cole County Circuit Court issued a ruling on December 8, 2009, affirming the Commission’s Report and Order. OPC, Praxair and Explorer Pipeline have filed appeals with the Western District Court of Appeals.

Kansas

On November 4, 2009, we filed a request with the KCC for an annual increase in base rates for our Kansas electric customers in the amount of $5.2 million, or 24.6%. This request was primarily to allow us to recover capital expenditures associated with environmental upgrades at Iatan 1 completed in 2009 and at our Asbury plant completed in 2008 and our investment in new generating units at Iatan 2, the Plum Point Generating Station and our Riverton 12 unit that went on line in 2007. A stipulated agreement was filed on May 4, 2010, and approved by the KCC on June 25, 2010, calling for a $2.8 million, or 12.4%, increase in base rates effective July 1, 2010. We will defer depreciation and operating and maintenance expense on both Plum Point and Iatan 2 from their respective in-service dates until the effective date for rates from the next Kansas case, expected to be an abbreviated rate case that will be filed within the next year. These deferrals will be recovered over a 3-5 year period as determined in that next case. We will record AFUDC on all Plum Point and Iatan 2 capital expenditures incurred after January 31, 2010.

Oklahoma

On March 25, 2010, we requested a capital cost recovery rider (CCRR) at the OCC. The rider is designed to recover the carrying costs on our capital investment for generation, transmission and distribution assets that have been added to the system since our last Oklahoma general rate case (May 2003), as well as investments made on an ongoing basis. As requested, the operation of the CCRR would increase our operating revenue in Oklahoma in a series of three steps to be followed with a general rate case in 2011. If the CCRR is authorized by the OCC, it is expected to result in a maximum overall increase in Oklahoma revenues of approximately $3 million, or approximately 33%.

Arkansas

On June 1, 2010, we advised the Arkansas Public Service Commission of the intention to file an application for a general change or modification in our rates, charges and tariffs no sooner than 60 days and no later than 90 days from the date of notice.

FERC

On March 12, 2010, we filed GFR tariffs with the FERC which we propose to be utilized for our wholesale customers. On May 28, 2010, the FERC issued an order that conditionally approved our GFR filing subject to refund effective June 1, 2010. On June 30, 2010, three of our on-system wholesale customers were granted intervention in the GFR rate case. Also on May 28, 2010, we filed a notice with the FERC requesting termination of the current bundled service agreements for our wholesale customers effective July 31, 2010. On July 28, 2010, the FERC issued an order accepting and suspending the proposed terminations for a nominal period to become effective July 31, 2010, subject to refund. The FERC’s order also consolidated the GFR and termination proceedings.

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Gas Segment

On June 5, 2009, we filed a request with the MPSC for an annual increase in base rates for our Missouri gas customers in the amount of $2.9 million, or 4.9%. In this filing, we requested recovery of the ongoing cost of operating and maintaining our 1,200-mile gas distribution system and a return on equity of 11.3%. On February 24, 2010, the MPSC unanimously approved an agreement among the Office of the Public Counsel (OPC), the MPSC staff and Empire for an increase of $2.6 million. Pursuant to the Agreement, new rates went into effect on April 1, 2010.

COMPETITION

Electric Segment

SPP-RTO

Energy Imbalance Services:  On February 1, 2007, the Southwest Power Pool (SPP) regional transmission organization (RTO) launched its energy imbalance services market (EIS). In general, the SPP RTO EIS market provides real time energy for most participating members within the SPP regional footprint. Imbalance energy prices are based on market bids and status/availability of dispatchable generation and transmission within the SPP market footprint. In addition to energy imbalance service, the SPP RTO performs a real time security-constrained economic dispatch of all generation voluntarily offered into the EIS market to the market participants to also serve the native load.

Day-Ahead Market:  The SPP and its members have been evaluating the costs and benefits on expanding the EIS market into a full day ahead energy market with a co-optimized ancillary services market, which will include the consolidation of all SPP balancing authorities, including ours, into a single SPP balancing authority. On April 28, 2009, the SPP Regional State Committee (SPP RSC), whose members include state commissioners from our four state commissions, and the SPP Board of Directors (SPP BOD) endorsed a cost benefit report that recommended the SPP RTO move forward with the development of a day-ahead market with unit commitment and co-optimized ancillary services market (Day-Ahead Market) and implement the complete Day-Ahead Market as soon as practical, which is anticipated in late 2013 or early 2014. As part of the Day-Ahead Market, the SPP RTO will create, prior to implementation of such market, a single NERC approved balancing authority to take over balancing authority responsibilities for its members, including us, which is expected to provide operational and economic benefits for our customers. The implementation of the Day-Ahead Market will replace the existing EIS market, which to date has, and is expected to continue to, provide benefits for our customers.

SPP Regional Transmission Development:  On August 15, 2008, the SPP filed with the FERC proposed revisions to its open access transmission pro forma tariff (OATT) to establish a process for including a “balanced portfolio” of economic transmission upgrades in the annual SPP Transmission Expansion Plan. The cost of such upgrades will be recovered through a regional rate allocated to SPP members based on their load ratio share within SPP’s market area of the balanced portfolio’s cost. On October 16, 2008, the FERC accepted the balanced portfolio approach, which sets forth the selection process of a group of projects and regional cost allocation rules based on projected benefits and allocated costs over a ten year period. The plan will be balanced if the portfolio is cost beneficial for each zone, including ours, within the SPP. A balanced portfolio could include projects below the 345 kv level (which is the bright line voltage level for projects to be included in the portfolio) to increase benefits to a particular zone to achieve balance of benefits and costs over the ten year study period. On April 28, 2009, the SPP RSC and the SPP BOD approved the first set of balanced portfolio extra high voltage transmission projects to be constructed within the SPP region. The transmission expansion projects, totaling over $700 million, include projects in Missouri, Kansas, Arkansas, Oklahoma, Nebraska and Texas. We anticipate this set of transmission expansion projects will provide long term benefits to our customers yet expect our

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share of the net allocated costs to be immaterial. Also on April 28, 2009, the SPP RSC and BOD approved a new report that recommended restructuring of the SPP’s regional planning processes, which would establish an integrated planning process for reliability, transmission service and economic transmission projects, based on a new set of planning principles that focus on the construction of a more robust transmission system large enough in both scale and geography to provide flexibility to meet SPP members’ and customers’ future needs. We will continue to actively participate in the development of these new processes as well as cost allocation and recovery issues with members, prospective customers and the state commission representatives to the SPP RSC.

On October 27, 2009, the SPP BOD endorsed a new transmission cost allocation method to replace the existing FERC accepted cost allocation method for new transmission facilities needed to continue to reliably and economically serve SPP customers, including ours, well into the future. On April 19, 2010, SPP filed revisions to its OATT to adopt a new highway/byway cost allocation methodology which require SPP BOD approved transmission projects of 300 kV or larger to be funded by the region at 100%, transmission projects between 100 kV and 300 kV to receive 33% regional funding with individual constructing zones to pay 67% of those projects built within the zone. For projects under 100kV, the constructing zones would pay 100% of the cost. On May 17, 2010, we filed a joint protest at the FERC with other SPP members based on our disagreement with the SPP on the allocation percentages and various other issues. On June 17, 2010, the FERC unconditionally approved the new highway/byway cost allocation method. We and other members of the SPP filed a Request for Rehearing on July 19, 2010. It is uncertain as to when the FERC will rule on our Request for Rehearing. On May 17, 2010, in a related but separate filing, the SPP filed revisions to its OATT to incorporate a modified transmission planning process, the Integrated Transmission Plan (ITP) that the SPP will use to determine it’s near and long term transmission needs to meet reliability and provide economic benefits throughout the SPP region. On June 7, 2010, we made a joint protest filing at the FERC regarding the ITP filing which expressed our concerns over the lack of explicit provisions in the SPP OATT to protect SPP customers from the approval of transmission projects that may not sufficiently benefit the SPP region. On July 15, 2010, the FERC issued an order conditionally accepting SPP proposed ITP planning process and tariff provisions to be effective on July 17, 2010 and ordered SPP to make a compliance filing by August 15, 2010 on the timing of ITP business practices and factors to be considered for changing the allocation of costs methods for dual winding high voltage transformers. We and the other parties to the SPP ITP joint filing plan to file a formal Request for Rehearing at the FERC on the ITP order by August 15, 2010.

FERC Market Power Order

As part of our market based pricing authority from the FERC, we are required to conduct a market power analysis within our service territory and within the SPP RTO region every three years. We filed our triennial market power analysis with the FERC on July 30, 2009, concluding there were no material changes to our market position. As a result, we did not anticipate any changes to our existing market based rate authority. On July 13, 2010, the FERC issued an order accepting our triennial market power analysis and authorized the continuation of our market based rate authority for wholesale transactions outside our service territory.

Other FERC Activity

On June 21, 2007, the FERC issued an Advance Notice of Proposed Rulemaking (ANOPR) on potential reforms to improve operations in organized wholesale power markets, such as the SPP RTO in which we participate. On October 16, 2008, the FERC issued its Final Order on Wholesale Competition in Regions with Organized Electric Markets. The Final Order will affect us as it directly affects the SPP RTO. The Final Order addresses four key areas for amending its regulations in Wholesale Competition for RTOs and Independent System Operators (ISOs): (1) demand response and market pricing during periods of operating reserve shortage; (2) long-term power contracting; (3) market monitoring policies; and (4) the responsiveness of RTOs and ISOs to stakeholders and

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customers. We continue to be involved in the SPP RTO and our state commission discussions on compliance of these new rules.

On May 21, 2009, the FERC issued an order clarifying that, going forward, small public utilities that have been granted waiver of Order No. 889 (Open Access Same Time Information Systems (OASIS) requirement) and the Standards of Conduct for transmission operations, which includes us, are required to submit a notification filing if there has been a material change in facts that may affect the basis on which a public utility’s waiver was premised. The Standards of Conduct generally govern the communications between our day to day transmission operations personnel and our day to day wholesale marketing and sales personnel. We submitted our filing on July 13, 2009 in which we stated our belief that continuation of our waiver, issued in 1997 and reaffirmed in 2004, was appropriate and reasonable. Based on the May 21, 2009 order, it is possible that the FERC will revoke our waiver which would impact communication between our transmission and wholesale marketing and sales functions and operations within our organization. As part of our filing, we sought a twelve month extension in order to comply with the Standard of Conduct requirements in the event the FERC determined that revoking our waiver was appropriate. The FERC’s decision on this and other Standard of Conduct waiver filings is pending. As of July 19, 2010, we have voluntarily taken steps to allow us to comply with a FERC order with minimal additional impact.

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

Overview.     Our primary sources of liquidity are cash provided by operating activities, short-term borrowings under our commercial paper program (which is supported by our credit facilities) and borrowings from our unsecured revolving credit facility. As needed, we raise funds from the debt and equity capital markets, including through our existing shelf registration statement, to fund our liquidity and capital resource needs.

Our issuance of various securities, including equity, long-term and short-term debt, is subject to customary approval or authorization by state and federal regulatory bodies including state public service commissions and the SEC. We estimate that internally generated funds (funds provided by operating activities less dividends paid) will provide only a portion of the funds required in 2010 for our budgeted capital expenditures (as discussed in “Capital Requirements and Investing Activities” below). Although our working capital was negative as of June 30, 2010, we believe the amounts available to us under our credit facilities and the issuance of debt and equity securities together with this cash provided by operating activities will allow us to meet our needs for working capital, pension contributions, our continuing construction expenditures, anticipated debt redemptions, interest payments on debt obligations, dividend payments and other cash needs through the next several years.

We will continue to evaluate our need to increase available liquidity based on our view of working capital requirements, including the timing of our construction programs and other factors. The following table provides a summary of our operating, investing and financing activities for the periods shown below:

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Summary of Cash Flows

	Six Months Ended June 30,
(in millions)	2010			2009
Cash provided by (used in):
Operating activities	$	42.0		$	60.0
Investing activities	(59.2		)	(84.0		)
Financing activities	18.3			24.6
Net change in cash and cash equivalents	$	1.1		$	0.6

Cash flow from Operating Activities

We prepare our statement of cash flows using the indirect method. Under this method, we reconcile net income to cash flows from operating activities by adjusting net income for those items that impact net income but may not result in actual cash receipts or payments during the period. These reconciling items include depreciation and amortization, pension costs, deferred income taxes, equity AFUDC, changes in commodity risk management assets and liabilities and changes in the consolidated balance sheet for working capital from the beginning to the end of the period.

Period-over-period changes in our operating cash flows are attributable primarily to working capital changes resulting from the impact of weather, the timing of customer collections, payments for natural gas and coal purchases and the effects of deferred fuel recoveries. The increase in natural gas prices directly impacts the cost of gas stored in inventory.

Six Months Ended June 30, 2010 Compared to 2009.  During the six months ended June 30, 2010, our net cash flow provided from operating activities was $42.0 million, a decrease of $18.0 million or 30.0% from 2009. This decrease was primarily a result of:

·Changes in net income - $(2.6) million.

·Draw down of the commodity risk management margin accounts through settlement of hedged positions in 2009 - $(5.4) million.

·Changes in seasonal levels of inventory, including the effect of building coal inventories at Plum Point and Iatan 2 - $(9.7) million.

·Changes in prepaid expenses and deferred charges primarily related to deferred fuel costs and increased bank fees - $(2.8) million.

·Changes in accrued fuel and construction liabilities - $2.7 million

Capital Requirements and Investing Activities

Our net cash flows used in investing activities decreased $24.7 million during the six months ended June 30, 2010 as compared to the same period in 2009.

Our capital expenditures incurred totaled approximately $56.6 million during the six months ended June 30, 2010 compared to $82.3 million for the six months ended June 30, 2009. The decrease was primarily the result of a decrease in electric plant additions and replacements, storm expenditures and new generation construction in 2010.

A breakdown of the capital expenditures for the six months ended June 30, 2010 and 2009 is as follows:

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	Capital Expenditures
(in millions)	2010			2009
Distribution and transmission system additions	$	16.0		$	17.2
New Generation — Plum Point Energy Station	5.3			9.0
New Generation — Iatan 2	30.6			31.5
Storms	—			6.3
Additions and replacements — electric plant	2.9			17.5
Gas segment additions and replacements	0.8			0.8
Transportation	0.8			0.8
Other (including retirements and salvage -net) (1)	(1.8		)	(1.6		)
Subtotal	54.6			81.5
Non-regulated capital expenditures (primarily fiber optics)	2.0			0.8
Subtotal capital expenditures incurred (2)	56.6			82.3
Adjusted for capital expenditures payable (3)	2.6			2.2
Total cash outlay	$	59.2		$	84.5

(1) Other includes equity AFUDC of $(3.7) million and $(2.6) million for 2010 and 2009, respectively.

(2) Expenditures incurred represent the total cost for work completed for the projects during the reporting period. Discussion of capital expenditures throughout this 10-Q is presented on this basis. These capital expenditures include AFUDC, capital expenditures to retire assets and benefits from salvage.

(3) The amount of expenditures paid/(unpaid) at the end of the reporting period to adjust to actual cash outlay reflected in the Investing Activities section of the Statement of Cash Flows.

None of our cash requirements for capital expenditures during the second quarter of 2010 were satisfied internally from operations (funds provided by operating activities less dividends paid). The amounts of such requirements were satisfied from short-term borrowings and proceeds from our sales of common stock and debt securities discussed below.

We estimate that internally generated funds will provide approximately 93% of the funds required for the remainder of our budgeted 2010 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

Our net cash flows provided by financing activities decreased $6.3 million during the first six months of 2010 as compared to the same period in 2009.

On July 26, 2010, we issued a notice to call all $48.3 million aggregate principal amount of our Senior Notes, 7.05% Series due 2022 for redemption on August 27, 2010. We expect to finance the redemption with an offering of first mortgage bonds. The redemption is conditioned upon the consummation of this offering. If we are unable to complete this offering, the notice of redemption would be of no effect unless we waive this condition.

On May 28, 2010, we issued $100 million principal amount of 4.65% first mortgage bonds due June 1, 2020. The net proceeds (after payment of expenses) of approximately $98.9 million, were used to redeem all 2 million outstanding shares of our 8.5% trust preferred securities, totaling $50 million, on June 28, 2010 and to repay short-term debt which was incurred, in part, to fund the repayment, at maturity, of our 6.5% first mortgage bonds due 2010.

We successfully completed our equity distribution program during the second quarter of 2010 and used the net proceeds to repay short-term debt and for general corporate purposes, including the funding of our current construction program. During the second quarter of 2010, we issued and sold 1,192,644 shares of our common stock pursuant to this equity distribution program, at an average price per share of $18.60, resulting in net proceeds to us of approximately $21.5 million (after payment of approximately $0.7 million in commissions to the sales agent). Since inception of the program, in the aggregate, we issued and sold 6,535,216 shares pursuant to the

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program, at an average price per share of $18.36, resulting in net proceeds to us of approximately $116.0 million. See Note 6 of “Notes to Consolidated Financial Statements (Unaudited)” for additional information regarding our equity distribution program.

We had $40 million in short-term debt as of June 30, 2010 versus $72 million as of June 30, 2009.

On March 27, 2009, we issued $75 million principal amount of 7% first mortgage bonds due April 1, 2024. The net proceeds (after payment of expenses) of approximately $72.6 million were used to repay short-term debt incurred, in part, to fund our current construction program.

We have a $400 million shelf registration statement with the SEC, which became effective on August 15, 2008, covering our common stock, unsecured debt securities, preference stock, first mortgage bonds and trust preferred securities. As of June 30, 2010, $105 million remains available for issuance under this shelf registration statement. Of the original $400 million, $250 million was available for first mortgage bonds with $75 million remaining available after the issuance of $100 million in first mortgage bonds on May 28, 2010 and $75 million in first mortgage bonds on March 27, 2009. We plan to use a portion of the proceeds from issuances under this shelf to fund a portion of the capital expenditures for our new generation projects and to refinance long-term debt.

On July 15, 2005, we entered into a $150 million unsecured revolving credit facility which was scheduled to terminate on July 15, 2010. On March 14, 2006, we entered into the First Amended and Restated Unsecured Credit Agreement which amended and restated 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 reduced over a four year period in line with the amount of construction expenditures we owed for Plum Point Unit 1 and terminated on July 15, 2010. On January 26, 2010, we entered into the Second Amended and Restated Unsecured Credit Agreement which amended and restated this facility again. This agreement extends the termination date of the revolving credit facility from July 15, 2010 to January 26, 2013. In addition, the pricing and fees under the facility were amended. Interest on borrowings under the facility accrues at a rate equal to, at our option, (i) the highest of (A) the bank’s prime commercial rate, (B) the federal funds effective rate plus 0.5% or (C) one month LIBOR plus 1.0%, plus a margin or (ii) one month, two month or three month LIBOR, in each case, plus a margin. Each margin is based on our current credit ratings and the pricing schedule in the facility. As of the date hereof, and based on our current credit ratings, the LIBOR margin under the facility increased from 0.80% to 2.70%. A facility fee is payable quarterly on the full amount of the commitments under the facility and a usage fee is payable on the full amount of the commitments under the facility for any period in which we have drawn less than 33% of the total revolving commitments under the facility, in each case based on our current credit ratings. In addition, upon entering into the amended and restated facility, we paid an upfront fee to the revolving credit banks of $900,000 in the aggregate. The aggregate amount of the revolving commitments remained unchanged at $150 million and there were no other material changes to the terms of the facility. The 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 trust preferred securities) 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 trust preferred securities) for the trailing four fiscal quarters at the end of each fiscal quarter. Failure to maintain these ratios will result in an event of default under the credit facility and will prohibit us from borrowing funds thereunder. As of June 30, 2010, we are in compliance with these ratios. This credit facility is also subject to cross-default if we default on in excess of $10 million in the aggregate on our other indebtedness. This arrangement does not serve to legally restrict the use of our cash in the normal course of operations. There were no outstanding borrowings under this agreement at June 30, 2010. However, $40.0 million was used to back up our outstanding commercial paper.

On March 11, 2009, we entered into a $50 million unsecured credit agreement. This agreement, which terminated on July 15, 2010, provided for $50 million of revolving loans to be available to us for working capital, general corporate purposes and to back-up our use of

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commercial paper and was in addition to, and had substantially identical covenants and terms as (other than pricing) our Second Amended and Restated Unsecured Credit Agreement dated January 26, 2010 discussed above. At June 30, 2010, there were no borrowings under this agreement.

The principal amount of all series of first mortgage bonds outstanding at any one time under the EDE Mortgage is limited by terms of the mortgage to $1 billion. Substantially all of the property, plant and equipment of The Empire District Electric Company (but not its subsidiaries) is subject to the lien of the EDE Mortgage. Restrictions in the EDE mortgage bond indenture could affect our liquidity. The EDE Mortgage contains a requirement that for new first mortgage bonds to be issued, our net earnings (as defined in the EDE Mortgage) for any twelve consecutive months within the fifteen months preceding issuance must be two times the annual interest requirements (as defined in the EDE Mortgage) on all first mortgage bonds then outstanding and on the prospective issue of new first mortgage bonds. Our earnings for the twelve months ended June 30, 2010 would permit us to issue approximately $288.7 million of new first mortgage bonds based on this test with an assumed interest rate of 6.0%. In addition to the interest coverage requirement, the EDE Mortgage provides that new bonds must be issued against, among other things, retired bonds or 60% of net property additions. At June 30, 2010, we had retired bonds and net property additions which would enable the issuance of at least $613.2 million principal amount of bonds if the annual interest requirements are met. As of June 30, 2010, we are in compliance with all restrictive covenants of the EDE Mortgage.

The principal amount of all series of first mortgage bonds outstanding at any one time under the EDG Mortgage is limited by terms of the mortgage to $300 million. Substantially all of the property, plant and equipment of The Empire District Gas Company is subject to the lien of the EDG Mortgage. The EDG Mortgage contains a requirement that for new first mortgage bonds to be issued, the amount of such new first mortgage bonds shall not exceed 75% of the cost of property additions acquired after the date of the Missouri Gas acquisition. The mortgage also contains a limitation on the issuance by EDG of debt (including first mortgage bonds, but excluding short-term debt incurred in the ordinary course under working capital facilities) unless, after giving effect to such issuance, EDG’s ratio of EBITDA (defined as net income plus interest, taxes, depreciation, amortization and certain other non-cash charges) to interest charges for the most recent four fiscal quarters is at least 2.0 to 1. As of June 30, 2010, this test would allow us to issue approximately $5.2 million principal amount of new first mortgage bonds.

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

	Fitch	Moody’s	Standard & Poor’s
Corporate Credit Rating	n/r*	Baa2	BBB-
First Mortgage Bonds	BBB+	A3	BBB+
Senior Notes	BBB	Baa2	BBB-
Commercial Paper	F2	P-2	A-3
Outlook	Stable	Stable	Stable

*Not rated

On March 24, 2010, Standard & Poor’s issued a report with our ratings unchanged and upgraded our business profile to “excellent” from “strong”. On May 14, 2010, Moody’s upgraded our First Mortgage Bonds from Baa1 to A3 and upgraded its outlook from negative to stable. Moody’s affirmed all of our other ratings. On April 1, 2010, Fitch affirmed our ratings and revised their rating outlook to stable. The revision took into consideration the anticipated completion of our five-year baseload capital expenditure program in 2010 and assumes we will receive timely and adequate regulatory recovery of newly completed investments.

A security rating is not a recommendation to buy, sell or hold securities. Each rating is subject to revision or withdrawal at any time by the assigning rating organization. Each security rating agency has its own methodology for assigning ratings, and, accordingly, each rating should be considered independently of all other ratings.

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CONTRACTUAL OBLIGATIONS

Material changes to our contractual obligations at June 30, 2010, compared to December 31, 2009 consist of the following. We issued $100 million principal amount of 4.65% first mortgage bonds on May 28, 2010 which are due June 1, 2020 and require semi-annual interest payments of $2.3 million. Funds from this offering were used in part to refinance $50 million of 8.5% Trust Preferred Securities on June 28, 2010 that were originally due 2031 and required quarterly interest payments totaling $4.3 million each year. The proceeds were also used to repay short-term debt which was incurred, in part, to fund the repayment of $50 million of 6.5% first mortgage bonds which matured April 1, 2010. We also entered into a contract in the second quarter of 2010 for the transportation of coal beginning June 30, 2010, which replaced a contract that expired June 29, 2010. The contract term is for six and one-half years and the minimum payments total approximately $91.9 million over the term of the contract. Minimum payments under this contract are as follows:  2010 - $7.9 million; 2011-2012 - $28.0 million; 2013-2014 - $28.0 million; and 2015 and thereafter - $28.0 million.

DIVIDENDS

Holders of our common stock are entitled to dividends if, as, and when declared by the Board of Directors, out of funds legally available therefore, subject to the prior rights of holders of any outstanding cumulative preferred stock and preference stock. Payment of dividends is determined by our Board of Directors after considering all relevant factors, including the amount of our retained earnings (which is essentially our accumulated net income less dividend payouts). As of June 30, 2010 our retained earnings balance was $0.6 million, compared to $10.3 million as of June 30, 2009, after paying out $13.1 million in dividends during the second quarter of 2010. A reduction of our dividend per share, partially or in whole, could have an adverse effect on our common stock price. On July 29, 2010, the Board of Directors declared a quarterly dividend of $0.32 per share on common stock payable September 15, 2010 to holders of record as of September 1, 2010.

Our diluted earnings per share were $0.40 for the six months ended June 30, 2010 and were $1.18 and $1.17 for the years ended December 31, 2009 and 2008, respectively. Dividends paid per share were $0.64 for the six months ended June 30, 2010 and $1.28 for each of the years ended December 31, 2009 and 2008.

Under Kansas corporate law, our Board of Directors may only declare and pay dividends out of our surplus or, if there is no surplus, out of our net profits for the fiscal year in which the dividend is declared or the preceding fiscal year, or both. Our surplus, under Kansas law, is equal to our retained earnings plus accumulated other comprehensive income/(loss), net of income tax. However, Kansas law does permit, under certain circumstances, our Board of Directors to transfer amounts from capital in excess of par value to surplus. In addition, Section 305(a) of the Federal Power Act (FPA) prohibits the payment by a utility of dividends from any funds “properly included in capital account”. There are no additional rules or regulations issued by the FERC under the FPA clarifying the meaning of this limitation. However, several decisions by the FERC on specific dividend proposals suggest that any determination would be based on a fact-intensive analysis of the specific facts and circumstances surrounding the utility and the dividend in question, with particular focus on the impact of the proposed dividend on the liquidity and financial condition of the utility.

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

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we amended the EDE Mortgage in order to provide us with more flexibility to pay dividends to our shareholders by increasing the basket available to pay dividends by $10.75 million, as described above. As of June 30, 2010, this restriction did not prevent us from issuing dividends.

OFF-BALANCE SHEET ARRANGEMENTS

We have no off-balance sheet arrangements that have or are reasonably likely to have a current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources, other than operating leases entered into in the normal course of business.

CRITICAL ACCOUNTING POLICIES

See “Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report Form 10-K for the year ended December 31, 2009 for a discussion of additional critical accounting policies. There were no changes in these policies in the quarter ended June 30, 2010.

RECENTLY ISSUED ACCOUNTING STANDARDS

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

Item 3.  Quantitative and Qualitative Disclosures about Market Risk

Our fuel procurement activities involve primary market risk exposures, including commodity price risk and credit risk. Commodity price risk is the potential adverse price impact related to the fuel procurement for our generating units. Credit risk is the potential adverse financial impact resulting from non-performance by a counterparty of its contractual obligations. Additionally, we are exposed to interest rate risk which is the potential adverse financial impact related to changes in interest rates.

Market Risk and Hedging Activities.

Prices in the wholesale power markets often are extremely volatile. This volatility impacts our cost of power purchased and our participation in energy trades. If we were unable to generate an adequate supply of electricity for our customers, we would attempt to purchase power from others. Such supplies are not always available. In addition, congestion on the transmission system can limit our ability to make purchases from (or sell into) the wholesale markets.

We engage in physical and financial trading activities with the goals of reducing risk from market fluctuations. In accordance with our established Energy Risk Management Policy, which typically includes entering into various derivative transactions, we attempt to mitigate our commodity market risk. Derivatives are utilized 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.

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 69.89% of our 2009 generation fuel supply need through coal. Approximately 88% of our 2009 coal supply was Western coal. We have contracts to supply a portion of the fuel for our coal plants through 2013. These contracts satisfy approximately 98% of our anticipated fuel requirements for 2010, 59% for 2011, 28% for 2012 and 30% of our 2013 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.

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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 manage our costs to avoid 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 expenditures and improve predictability. As of July 23, 2010, 80%, or 2.8 million Dths, of our anticipated volume of natural gas usage for our electric operations for the remainder of 2010 is hedged.

Based on our expected natural gas purchases for our electric operations for the next twelve months, if average natural gas prices should increase 10% more than the price at June 30, 2010, our natural gas cost would increase by approximately $1.4 million based on our June 30 2010 total hedged positions for the next twelve months. However, this is probable of recovery through fuel adjustment mechanisms. We have a fuel cost recovery mechanism in all of our jurisdictions, which significantly reduces the impact of fluctuating fuel costs.

We attempt to mitigate a portion of our natural gas price risk associated with our gas segment using physical forward purchase agreements, storage and derivative contracts. As of June 30, 2010, we have 1.0 million Dths in storage on the three pipelines that serve our customers. This represents 52% of our storage capacity. We have an additional 0.4 million Dths hedged through financial derivative and physical contracts. Our long-term hedge strategy is to mitigate price volatility for our customers by hedging a minimum of 50% of the current year, up to 50% of the second year and up to 20% of third year expected gas usage by the beginning of the ACA year at September 1. However, due to purchased natural gas cost recovery mechanisms for our retail customers, fluctuations in the cost of natural gas have little effect on income.

Credit Risk.

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. See Note 4 of “Notes to Consolidated Financial Statements (Unaudited)” regarding agreements containing credit risk contingent features. 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. Conversely, we are required to post collateral with counterparties at certain thresholds, which is typically the result of changes in commodity prices. Amounts reported as margin deposit liabilities represent counterparty funds we hold that result from various trading counterparties exceeding agreed-upon credit exposure thresholds. Amounts reported as margin deposit assets represent our funds held on deposit for our NYMEX contracts with our broker and other financial contracts with other counterparties that resulted from us exceeding agreed-upon credit limits established by the counterparties. The following table depicts our margin deposit assets at June 30, 2010 and December 31, 2009. There were no margin deposit liabilities at these dates.

(in millions)	June 30, 2010		December 31, 2009
Margin deposit assets	$	3.1	$	2.9

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. Below is a table showing our net credit exposure at June 30, 2010, reflecting that our counterparties are exposed to Empire for the net unrealized mark-to-market losses for physical forward and financial natural gas contracts carried at fair value.

(in millions)
Net unrealized mark-to-market losses for physical forward natural gas contracts	$	15.1
Net unrealized mark-to-market losses for financial natural gas contracts	3.7
Net credit exposure	$	18.8

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The $3.7 million net unrealized mark-to-market loss for financial natural gas contracts is comprised of $4.1 million that our counterparties are exposed to Empire for unrealized losses and $0.4 million of unrealized gains from our counterparties. We are holding no collateral from any counterparty since we are below the $10 million mark-to-market collateral threshold in our agreements. As noted above, as of June 30, 2010, we have $3.1 million on deposit for NYMEX contract exposure to Empire, of which $3.0 million represents our collateral requirement. In addition, if NYMEX gas prices decreased 25% from their June 30, 2010 levels, we would be required to post an additional $2.9 million in collateral. If these prices increased 25%, our collateral requirement would decrease $2.6 million. Our other counterparties would not be required to post collateral with Empire.

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.

Interest Rate Risk.

We are exposed to changes in interest rates as a result of financing through our issuance of commercial paper and other short-term debt. We manage our interest rate exposure by limiting our variable-rate exposure (applicable to commercial paper and borrowings under our unsecured credit agreement) to a certain percentage of total capitalization, as set by policy, and by monitoring the effects of market changes in interest rates.

If market interest rates average 1% more in 2010 than in 2009, our interest expense would increase, and income before taxes would decrease by less than $0.3 million. This amount has been determined by considering the impact of the hypothetical interest rates on our highest month-end commercial paper balance for 2009. 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.

Item 4.   Controls and Procedures

As of the end of the period covered by this report, an evaluation was carried out, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as such term is defined in Rule 13a-15(e) of the Securities Exchange Act of 1934). Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of June 30, 2010.

There have been no changes in our internal control over financial reporting that occurred during the second quarter of 2010 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II.  OTHER INFORMATION

Item 1.  Legal Proceedings

Platte County Levee Lawsuit

On May 22, 2009, a suit was filed in the Circuit Court of Platte County Missouri by several individuals and Class Representatives alleging damages to land, structures, equipment and devastation of crops due to inappropriate management of the levee system around the Iatan Generating Station, of which we are 12% owners. No procedural schedule has been established and we are unable to predict the outcome of the law suit.

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Item 1A.  Risk Factors.

There have been no material changes to the factors disclosed in Part I, Item 1-A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2009.

Item 5.  Other Information.

For the twelve months ended June 30, 2010, our ratio of earnings to fixed charges was 2.23x.  See Exhibit (12) hereto.

Item 6.  Exhibits.

(a)Exhibits.

(4) Thirty-Fifth Supplemental Indenture, dated as of May 28, 2010, to the Indenture of Mortgage and Deed of Trust dated as of September 1, 1944, as amended and supplemented, among the Company, The Bank of New York Mellon Trust Company, N.A. and UMB Bank & Trust, N.A. (Incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K dated May 28, 2010 and filed May 28, 2010, File No. 1-3368).

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

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

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

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

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

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

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SIGNATURES

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

	THE EMPIRE DISTRICT ELECTRIC COMPANY
	Registrant
	By	/s/ Gregory A. Knapp
		Gregory A. Knapp
		Vice President — Finance and Chief Financial Officer
	By	/s/ Laurie A. Delano
		Laurie A. Delano
		Controller, Assistant Secretary and Assistant Treasurer
August 5, 2010

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