Empire District Electric (EDE) 10-Q 2011 Q2 Quarterly report

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended June 30, 2011

or

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

For the transition period from                       to                      .

Commission file number: 1-3368

THE EMPIRE DISTRICT ELECTRIC COMPANY

(Exact name of registrant as specified in its charter)

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

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

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

Indicate by check mark 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 x  No o

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

Large accelerated filer 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 1, 2011, 41,949,930 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	37
	Rate Matters	50
	Competition	53
	Liquidity and Capital Resources	53
	Contractual Obligations	57
	Dividends	57
	Off-Balance Sheet Arrangements	58
	Critical Accounting Policies.	58
	Recently Issued Accounting Standards.	58
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	58
Item 4.	Controls and Procedures	60
Part II-	Other Information:
Item 1.	Legal Proceedings	61
Item 1A.	Risk Factors	61
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds - (none)
Item 3.	Defaults Upon Senior Securities - (none)
Item 5.	Other Information	61
Item 6.	Exhibits	61
	Signatures	63

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, impacts from the 2011 tornado, 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, fuel and purchased power costs and 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 and regulation, including environmental regulation (such as NOx, SO2, mercury, ash and CO2) and health care regulation;

·competition, including the 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 (including as a result of being required to report in accordance with IFRS rather than U. S. GAAP);

·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;

·the effect of changes in our credit ratings on the availability and 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
	2011			2010
	($-000’s except per share amounts)
Operating revenues:
Electric	$	119,903		$	106,249
Gas	7,303			6,516
Water	426			436
Other	1,461			1,281
	129,093			114,482
Operating revenue deductions:
Fuel and purchased power	47,228			44,255
Cost of natural gas sold and transported	2,712			2,265
Regulated operating expenses	19,085			19,272
Other operating expenses	649			480
Maintenance and repairs	10,540			9,600
Depreciation and amortization	16,888			13,586
Provision for income taxes	5,588			4,439
Other taxes	7,269			6,306
	109,959			100,203
Operating income	19,134			14,279
Other income and (deductions):
Allowance for equity funds used during construction	70			1,913
Interest income	16			52
Benefit/(provision) for other income taxes	9			(46		)
Other - non-operating expense, net	(174		)	(256		)
	(79		)	1,663
Interest charges:
Long-term debt	10,640			10,083
Trust preferred securities	—			1,027
Short-term debt	16			245
Allowance for borrowed funds used during construction	(58		)	(2,430		)
Other	(718		)	(352		)
	9,880			8,573
Net income	$	9,175		$	7,369
Weighted average number of common shares outstanding - basic	41,811			40,623
Weighted average number of common shares outstanding - diluted	41,846			40,654
Total earnings per weighted average share of common stock — basic and diluted	$	0.22		$	0.18
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,
		2011			2010
		($-000’s except per share amounts)
Operating revenues:
Electric		$	247,838		$	219,849
Gas		28,292			31,076
Water		852			870
Other		2,839			2,581
		279,821			254,376
Operating revenue deductions:
Fuel and purchased power		101,445			94,939
Cost of natural gas sold and transported		14,752			17,375
Regulated operating expenses		38,801			38,189
Other operating expenses		1,123			968
Maintenance and repairs		19,782			17,407
Depreciation and amortization		34,221			26,771
Provision for income taxes		12,857			14,328
Other taxes		15,859			14,042
		238,840			224,019
	��
Operating income		40,981			30,357
Other income and (deductions):
Allowance for equity funds used during construction		70			3,653
Interest income		40			122
Benefit/(provision) for other income taxes		33			(91		)
Other - non-operating expense, net		(460		)	(503		)
		(317		)	3,181
Interest charges:
Long-term debt		21,273			20,568
Trust preferred securities		—			2,090
Short-term debt		47			490
Allowance for borrowed funds used during construction		(81		)	(4,845		)
Other		(1,672		)	(720		)
		19,567			17,583
Net income		$	21,097		$	15,955
Weighted average number of common shares outstanding - basic		41,738			39,618
Weighted average number of common shares outstanding - diluted		41,774			39,645
Total earnings per weighted average share of common stock — basic and diluted		$	0.51		$	0.40
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,
	2011			2010
	($-000’s except per share amounts)
Operating revenues:
Electric	$	510,899		$	443,971
Gas	48,101			52,384
Water	1,787			1,774
Other	5,934			5,170
	566,721			503,299
Operating revenue deductions:
Fuel and purchased power	205,805			188,629
Cost of natural gas sold and transported	23,991			29,457
Regulated operating expenses	79,904			75,698
Other operating expenses	2,106			1,937
Maintenance and repairs	39,146			33,827
Depreciation and amortization	66,106			52,853
Provision for income taxes	28,999			24,338
Other taxes	29,545			26,390
	475,602			433,129
Operating income	91,119			70,170
Other income and (deductions):
Allowance for equity funds used during construction	954			7,225
Interest income	94			202
Benefit/(provision) for other income taxes	61			(308		)
Other - non-operating expense, net	(996		)	(997		)
	113			6,122
Interest charges:
Long-term debt	42,664			42,106
Trust preferred securities	—			4,215
Short-term debt	188			828
Allowance for borrowed funds used during construction	(872		)	(8,466		)
Other	(3,285		)	(1,102		)
	38,695			37,581
Net income	$	52,537		$	38,711
Weighted average number of common shares outstanding — basic	41,596			37,645
Weighted average number of common shares outstanding — diluted	41,627			37,665
Total earnings per weighted average share of common stock — basic and diluted	$	1.26		$	1.03
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,
	2011		2010
	($-000’s)
Net income	$	9,175	$	7,369
Reclassification adjustments for loss included in net income or reclassified to regulatory asset or liability	—		950
Net change in fair market value of derivative contracts for period	—		676
Income taxes	—		(619		)
Comprehensive income	$	9,175	$	8,376

	Six Months Ended
	June 30,
	2011		2010
	($-000’s)
Net income	$	21,097	$	15,955
Reclassification adjustments for loss included in net income or reclassified to regulatory asset or liability	—		950
Net change in fair market value of derivative contracts for period	—		(5,325		)
Income taxes	—		1,667
Comprehensive income	$	21,097	$	13,247

	Twelve Months Ended
	June 30,
	2011			2010
	($-000’s)
Net income	$	52,537		$	38,711
Reclassification adjustments for loss included in net income or reclassified to regulatory asset or liability	4,864			7,853
Net change in fair market value of derivative contracts for period	(1,037		)	(7,434		)
Income taxes	(1,458		)	(160		)
Comprehensive income	$	54,906		$	38,970

See accompanying Notes to Consolidated Financial Statements.

7

THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS (UNAUDITED)

	June 30, 2011		December 31, 2010
	($-000’s)
Assets
Plant and property, at original cost:
Electric	$	2,032,740	$	2,001,142
Natural gas	63,973		63,581
Water	11,351		11,128
Other	33,472		32,264
Construction work in progress	20,916		9,337
	2,162,452		2,117,452
Accumulated depreciation and amortization	622,697		598,363
	1,539,755		1,519,089
Current assets:
Cash and cash equivalents	8,038		14,499
Accounts receivable — trade, net	44,500		41,380
Accrued unbilled revenues	18,559		23,595
Accounts receivable — other	14,941		25,445
Fuel, materials and supplies	50,157		45,557
Prepaid expenses and other	5,991		5,688
Regulatory assets	1,564		4,974
	143,750		161,138
Noncurrent assets and deferred charges:
Regulatory assets	193,843		189,404
Goodwill	39,492		39,492
Unamortized debt issuance costs	9,700		9,257
Other	4,443		2,931
	247,478		241,084
Total Assets	$	1,930,983	$	1,921,311

(Continued)

See accompanying Notes to Consolidated Financial Statements.

8

THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS (UNAUDITED) (Continued)

	June 30, 2011			December 31, 2010
	($-000’s)
Capitalization and Liabilities
Common stock, $1 par value, 41,918,432 and 41,576,869 shares issued and outstanding, respectively	$	41,918		$	41,577
Capital in excess of par value	616,547			610,579
(Accumulated deficit)/retained earnings	(167		)	5,468
Total common stockholders’ equity	658,298			657,624
Long-term debt (net of current portion):
Obligations under capital lease	4,882			4,995
First mortgage bonds and secured debt	488,279			488,577
Unsecured debt	199,536			199,500
Total long-term debt	692,697			693,072
Total long-term debt and common stockholders’ equity	1,350,995			1,350,696
						��
Current liabilities:
Accounts payable and accrued liabilities	57,811			58,820
Current maturities of long-term debt	902			881
Short-term debt	18,500			24,000
Customer deposits	11,021			11,061
Interest accrued	6,159			6,004
Other current liabilities	1,181			578
Unrealized loss in fair value of derivative contracts	1,264			760
Taxes accrued	9,945			3,935
Regulatory liabilities	264			1,243
	107,047			107,282
Commitments and contingencies (Note 7)
Noncurrent liabilities and deferred credits:
Regulatory liabilities	123,840			87,579
Deferred income taxes	226,377			212,003
Unamortized investment tax credits	19,449			19,597
Pension and other postretirement benefit obligations	78,345			93,405
Unrealized loss in fair value of derivative contracts	3,392			3,564
Other	21,538			47,185
	472,941			463,333
Total Capitalization and Liabilities	$	1,930,983		$	1,921,311

See accompanying Notes to Consolidated Financial Statements.

9

THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

	Six Months Ended
	June 30,
	2011			2010
	($-000’s)
Operating activities:
Net income	$	21,097		$	15,955
Adjustments to reconcile net income to cash flows from operating activities:
Depreciation and amortization	44,160			30,698
Pension and other postretirement benefit costs, net of contributions	(11,792		)	3,060
Deferred income taxes and unamortized investment tax credit, net	14,155			4,097
Allowance for equity funds used during construction	(70		)	(3,653		)
Stock compensation expense	1,097			1,670
Non-cash loss on derivatives	—			652
Other	(163		)	—
Cash flows impacted by changes in:
Accounts receivable and accrued unbilled revenues	12,418			6,246
Fuel, materials and supplies	(4,599		)	(1,591		)
Prepaid expenses, other current assets and deferred charges	(13,554		)	(5,879		)
Accounts payable and accrued liabilities	(11,666		)	(18,806		)
Interest, taxes accrued and customer deposits	6,125			8,400
Other liabilities and other deferred credits	5,623			1,137
Accumulated provision - rate refunds	603			—
Net cash provided by operating activities	63,434			41,986
Investing activities:
Capital expenditures — regulated	(40,022		)	(57,200		)
Capital expenditures and other investments — non-regulated	(1,339		)	(2,004		)
Net cash used in investing activities	(41,361		)	(59,204		)
Financing activities:
Proceeds from first mortgage bonds, net	—			99,786
Long-term debt issuance costs	—			(924		)
Debt financing costs	(815		)	—
Proceeds from issuance of common stock net of issuance costs	4,953			56,178
Repayment of first mortgage bonds	—			(50,000		)
Redemption of trust preferred securities	—			(50,000		)
Net short-term repayments	(5,500		)	(10,500		)
Dividends	(26,732		)	(25,464		)
Other	(440		)	(750		)
Net cash (used in)/provided by financing activities	(28,534		)	18,326
Net (decrease)/increase in cash and cash equivalents	(6,461		)	1,108
Cash and cash equivalents at beginning of period	14,499			5,620
Cash and cash equivalents at end of period	$	8,038		$	6,728

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, 2010.

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, 2010, of which there were none.

Note 2 - Recently Issued and Proposed Accounting Standards

Fair Value:  In May 2011, the Financial Accounting Standards Board (FASB) issued guidance clarifying how to measure and disclose fair value. The guidance is intended to result in common fair value measurement and disclosure requirements in U.S. Generally Accepted Accounting Principles (GAAP) and International Financial Reporting Standards. This guidance amends the application of the “highest and best use” concept to be used only in the measurement of fair value of nonfinancial assets, clarifies that the measurement of the fair value of equity-classified financial instruments should be performed from the perspective of a market participant who holds the instrument as an asset, clarifies that an entity that manages a group of financial assets and liabilities on the basis of its net risk exposure can measure those financial instruments on the basis of its net exposure to those risks, and clarifies when premiums and discounts should be taken into account when measuring fair value. The fair value disclosure requirements also were amended. The revised guidance will be applicable for interim and annual periods beginning after December 15, 2011. The application of this standard is not expected to have a material impact on our results of operations, financial position or liquidity.

Other Comprehensive Income:  In June 2011, the FASB amended the guidance governing the presentation of other comprehensive income. Under the revised guidance, items of net income and other comprehensive income may be presented in one single statement, or in two separate, but consecutive, statements. The statements are required to be presented with equal prominence as the other primary financial statements. The revised guidance will be applicable for interim and annual periods beginning after December 15, 2011. The application of this standard will not have an impact on our results of operations, financial position or liquidity.

See Note 1 under “Notes to Consolidated Financial Statements” in our Annual Report on Form 10-K for the year ended December 31, 2010 for further information regarding recently issued and proposed accounting standards.

Note 3— Regulatory Matters

Construction Accounting. The Missouri Public Service Commission (MPSC) approved a regulatory plan in 2005, allowing construction accounting. Construction accounting, for the purposes of this regulatory plan, was specific to Iatan 1 and Iatan 2 and allowed us to defer certain charges as regulatory assets. These deferred charges included depreciation, operations and maintenance and carrying costs related to operation of the facilities until the facilities were ultimately included in our

11

rates. The regulatory plan also required us to continue to defer the fuel and purchased power expense impacts of Iatan 2, which were approximately $8.4 million as of June 30, 2011 and are recorded in Non-Current Regulatory Liabilities. Construction accounting began for Iatan 2 in August 2010 when it met its in-service criteria on August 26, 2010. In addition, in our 2009 Missouri rate case, construction accounting was approved for Plum Point, which met its in-service criteria on August 13, 2010. Construction accounting for Plum Point applied only to construction costs incurred subsequent to February 28, 2010. All of these deferrals began at the in-service dates and are to be amortized over the life of the plants once such deferred costs are included in our rates, which for Iatan 2 and Plum Point was on June 15, 2011, the effective date of rates for our recently completed Missouri rate case. The deferral balances for these plants will be amortized at the weighted average of the current depreciation rates for these plants and recorded as operating expense. The amortization of the deferred Iatan 1 costs began in September 2010.

As part of a stipulated agreement in our 2009 Kansas rate case, approved by the KCC on June 25, 2010, we also 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, which was filed on June 17, 2011 as an abbreviated case. These deferrals will be recovered over a 3-5 year period as determined in that next case. (See Note 7 for additional details).

There have been a few changes to regulatory assets and liabilities regarding their rate base inclusion or amortizable lives since December 31, 2010. As a result of our recently completed Missouri rate case, a tracking mechanism has been created to track the 2010 Southwest Power Administration (SWPA) payment and associated taxes (see Note 12). The Missouri jurisdictional portion of the payment will be amortized over ten years and reflected as a reduction to fuel expense. The Arkansas jurisdictional portion of the 2010 SWPA payment will be amortized on a straight-line basis over a 50 year period and reflected in the fuel adjustment clause. A tracking mechanism was also created related to the Plum Point, Iatan 2 and Iatan common plant operating expenses. The tracker is to exclude consumables and SO2 allowances which are recovered through the fuel adjustment clause. A regulatory asset or liability will be recorded for the difference between the Missouri jurisdictional portion of actual expenses and the annual recovery allowance with a corresponding charge or credit to regulated operating expense.

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, 2011		December 31, 2010
Regulatory Assets:
Under recovered electric fuel and purchased power costs — current	$	1,564	$	4,974
Regulatory assets, current(1)	1,564		4,974
Pension and other postretirement benefits(2)	87,932		92,192
Income taxes	50,084		50,188
Unamortized loss on reacquired debt	12,355		13,099
Deferred operating and maintenance expenses	166		—
Unamortized loss on interest rate derivative	1,619		1,776
Asbury five-year maintenance	719		948
Storm costs(3)	6,351		7,733
Deferred construction accounting costs(4)	16,964		10,521
Asset retirement obligation	3,493		3,412
Under recovered electric fuel and purchased gas costs	2,980		—
Under recovered purchased gas costs — gas segment	—		439
Unsettled derivative losses — electric segment	3,489		3,166
Customer programs	2,988		2,119
System reliability — vegetation management	4,095		3,338
Other	608		473
Regulatory assets, long-term	193,843		189,404
Total	$	195,407	$	194,378

12

	June 30, 2011		December 31, 2010
Regulatory Liabilities:
Over recovered purchased gas costs — gas segment - current	$	264	$	1,243
Regulatory liabilities, current(1)	264		1,243
Cost of removal	67,794		62,756
SWPA payment for Ozark Beach lost generation	26,424		—
Income taxes	12,539		12,715
Unamortized gain on interest rate derivative	3,796		3,881
Pension and other postretirement benefits(5)	3,528		4,604
Deferred construction accounting costs — fuel	8,384		3,126
Over recovered electric fuel and purchased power costs	245		155
Over recovered purchased gas costs — gas segment	1,130		—
Other	—		342
Regulatory liabilities, long-term	123,840		87,579
Total	$	124,104	$	88,822

(1)  Reflects under or over 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 $0.2 million in pension and other postretirement benefit costs have been recognized since January 1, 2011 to reflect the amortization of the regulatory assets that were recorded at the time of the EDG acquisition of the Aquila, Inc. gas properties.

(3)  Primarily reflects ice storm costs incurred in 2007.

(4) Balances as of June 30, 2011	Deferred Carrying Charges		Deferred O&M	Depreciation	Total
Iatan 1	$	2,753	1,376	1,667	$	5,796
Iatan 2	$	3,925	4,244	2,648	$	10,817
Plum Point	$	66	173	112	$	351
Total					$	16,964

Balances as of December 31, 2010	Deferred Carrying Charges		Deferred O&M	Depreciation	Total
Iatan 1	$	2,779	1,388	1,682	$	5,849
Iatan 2	$	1,770	1,643	1,111	$	4,524
Plum Point	$	33	70	45	$	148
Total					$	10,521

(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 and other postretirement benefit costs. Since January 1, 2011, regulatory liabilities and corresponding expenses have been reduced by approximately $0.6 million as a result of ratemaking treatment.

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. In conjunction with the implementation of the Missouri fuel adjustment clause, the unrealized losses or gains from new derivatives used to hedge our fuel costs in our electric segment are recorded in regulatory assets or liabilities. All gains and losses from derivatives related to the gas segment are recorded in regulatory assets or liabilities. This is in accordance with the ASC guidance on regulated operations, given that those regulatory assets and liabilities are probable of recovery through our fuel adjustment mechanism.

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

13

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 and subject to our fuel adjustment clause.

As of June 30, 2011 and December 31, 2010, we have recorded the following assets and liabilities representing the fair value of derivative financial instruments, (in thousands):

		June 30,		December 31,
ASSET DERIVATIVES		2011		2010
Non-designated hedging instruments due to regulatory accounting	Balance Sheet Classification	Fair Value		Fair Value
Natural gas contracts, gas segment	Current assets	$	28	$	39
	Non-current assets and deferred charges	6		117
Natural gas contracts, electric segment	Current assets	—		—
	Non-current assets and deferred charges	52		77
Total derivatives assets		$	86	$	233

		June 30,		December 31,
LIABILITY DERIVATIVES		2011		2010
Non-designated hedging instruments due to regulatory accounting	Balance Sheet Classification	Fair Value		Fair Value
Natural gas contracts, gas segment	Current liabilities	$	67	$	252
	Non-current liabilities and deferred credits	15		2
Natural gas contracts, electric segment	Current liabilities	1,197		508
	Non-current liabilities and deferred credits	3,377		3,562
Total derivatives liabilities		$	4,656	$	4,324

Electric

At June 30, 2011, approximately $1.2 million of unrealized losses are applicable to financial instruments which will settle within the next twelve months.

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 settled contracts for the electric segment for each of the periods ended June 30, (in thousands):

Derivatives in Cash Flow Hedging	Income Statement Classification of	Amount of Gain / (Loss) Reclassed from OCI into Income (Effective portion)
Relationships - Electric	Gain / (Loss) on	Three Months Ended					Six Months Ended					Twelve Months Ended
Segment	Derivative	2011		2010			2011		2010			2011			2010
Commodity contracts	Fuel and purchased power expense	$	—	$	(950	)	$	—	$	(950	)	$	(4,864	)	$	(7,853	)
Total Effective — Electric Segment		$	—	$	(950	)	$	—	$	(950	)	$	(4,864	)	$	(7,853	)

Derivatives in Cash Flow Hedging	Statement of	Amount of Gain / (Loss) Recognized in OCI on Derivative (Effective portion)
Relationships - Electric	Comprehensive	Three Months Ended				Six Months Ended					Twelve Months Ended
Segment	Income	2011		2010		2011		2010			2011		2010
Commodity contracts	Fuel and purchased power expense	$	—	$	676	$	—	$	(5,325	)	$	1,037	$	(7,434	)
Total Effective — Electric Segment		$	—	$	676	$	—	$	(5,325	)	$	1,037	$	(7,434	)

There were no “mark-to-market” pre-tax gains/(losses) from ineffective portions of our hedging activities for the electric segment for the periods ended June 30, 2011 and 2010, respectively.

14

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 non-designated derivative instruments for the electric segment for each of the periods ended June 30, (in thousands):

Non-Designated Hedging Instruments - Due to	Balance Sheet Classification of	Amount of (Loss) Recognized on Balance Sheet
Regulatory Accounting	Gain / (Loss) on	Three Months Ended						Six Months Ended						Twelve Months Ended
Electric Segment	Derivatives	2011			2010			2011			2010			2011			2010
Commodity contracts	Regulatory (assets)/liabilities	$	(1,367	)	$	(445	)	$	(735	)	$	(1,737	)	$	(2,959	)	$	(1,938	)
Total Electric Segment		$	(1,367	)	$	(445	)	$	(735	)	$	(1,737	)	$	(2,959	)	$	(1.938	)

Non-Designated Hedging Instruments - Due to	Statement of Operations Classification of	Amount of (Loss) Recognized in Income on Derivative
Regulatory Accounting	Gain / (Loss) on	Three Months Ended						Six Months Ended						Twelve Months Ended
Electric Segment	Derivatives	2011			2010			2011			2010			2011			2010
Commodity contracts	Fuel and purchased power expense	$	(552	)	$	(135	)	$	(392	)	$	(397	)	$	(1,008	)	$	(1,521	)
Total Electric Segment		$	(552	)	$	(135	)	$	(392	)	$	(397	)	$	(1.008	)	$	(1.521	)

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 qualify for the normal purchase normal sale exemption. We have a process in place to determine if any future executed contracts that otherwise qualify for the normal purchase normal sale exception contain a price adjustment feature and will account for these contracts accordingly.

As of July 22, 2011, the following volumes and percentage of our anticipated volume of natural gas usage for our electric operations for the remainder of 2011 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 2011	80	%	1,322,500	790,000	$	5.913
2012	60	%	2,325,000	1,420,000	$	6.618
2013	41	%	2,020,000	1,440,000	$	6.079
2014	20	%	460,000	1,120,000	$	5.607
2015	7	%	—	700,000	$	5.562

We utilize the following procurement guidelines for our electric segment, allowing the flexibility to hedge up to 100% of the current year’s and 80% of any future year’s expected requirements while being cognizant of volume risk. The 80% guideline is an annual target and volumes up to 100% can be hedged in any given month. For years beyond year four, additional factors of long term uncertainty (including with respect to required volumes and counterparty credit) are also considered.

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

15

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, 2011, we had 0.7 million Dths in storage on the three pipelines that serve our customers. This represents 36.6% of our storage capacity.

The following table sets forth our long-term hedge strategy of mitigating price volatility for our customers by hedging a minimum of expected gas usage for the current winter season and the next two winter seasons by the beginning of the Actual Cost Adjustment (ACA) year at September 1 and illustrates our hedged position as of June 30, 2011 (in thousands).

Season	Minimum % Hedged	Dth Hedged Financial	Dth Hedged Physical	Dth in Storage	Actual % Hedged
Current	50%	460,000	301,714	735,606	45	%
Second	Up to 50%	310,000	—	—	9	%
Third	Up to 20%	—	—	—	—	%
Total		770,000	301,714	735,606

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).

Non-Designated Hedging	Balance Sheet Classification of	Amount of (Loss) Recognized on Balance Sheet
Instruments Due to Regulatory	Gain / (Loss) on	Three Months Ended						Six Months Ended						Twelve Months Ended
Accounting - Gas Segment	Derivatives	2011			2010			2011			2010			2011			2010
Commodity contracts	Regulatory (assets)/liabilities	$	(175	)	$	(52	)	$	(271	)	$	(121	)	$	(717	)	$	(142	)
Total - Gas Segment		$	(175	)	$	(52	)	$	(271	)	$	(121	)	$	(717	)	$	(142	)

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, 2011 is $0.7 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, 2011, we would have been required to post $0.7 million of collateral with the counterparty. On June 30, 2011, we had no collateral posted with this 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 other than quoted prices in active markets that are either directly or indirectly observable; and (iii)

16

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 2 fair value measurements consist of both quoted price inputs and inputs that are derived principally from or corroborated by observable market data. Our Level 3 fair value measurements consist of both quoted price inputs and unobservable inputs.

The guidance also requires that the fair value measurements 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, 2011 and December 31, 2010.

($ in 000’s)

				Fair Value Measurements at Reporting Date Using
Description	Liabilities at Fair Value			Quoted Prices in Active Markets for Identical Liabilities (Level 1)			Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
				June 30, 2011
Net derivative liabilities*	$	(4,570	)	$	(4,570	)	$	—	$	—
				December 31, 2010
Net derivative liabilities*	$	(4,091	)	$	(4,091	)	$	—	$	—

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

The following table presents the change in net fair value of our Level 3 assets/liabilities during the twelve months ended June 30, 2011 and 2010. There were no Level 3 assets/liabilities for the three and six months ended June 30, 2011 and 2010.

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

	2011		2010
($ in 000’s)	Net Derivatives(1)		Net Derivatives(1)
Beginning Balance, July 1,	$	—	$	3,532
Total gains or (losses) (realized/unrealized)
Included in earnings (or changes in net assets)	—		—
Included in comprehensive income			(295		)
Purchases, issuances, and settlements	—		—
Transfers out of Level 3(2) (3)			(3,237		)
Ending Balance, June 30,	$	—	$	—
Changes in unrealized gains relating to assets still held at reporting date	$	—	$	(295	)

(1) Net derivatives at June 30, 2011 and 2010 included no derivative assets or 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, 2011, was $689 million compared to a fair market value of approximately $688 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, 2011 or that will be realizable in the future.

17

Note 6— Financing

On January 28, 2011, we filed a $400 million shelf registration statement with the SEC covering our common stock, unsecured debt securities, preference stock, and first mortgage bonds. This shelf registration statement became effective on February 7, 2011. We plan to use proceeds under this shelf to fund capital expenditures, refinancings of existing debt or general corporate needs during the effective period. The issuance of securities under this shelf is subject to the receipt of local regulatory approvals.

On January 26, 2010, we entered into the Second Amended and Restated Unsecured Credit Agreement which amended and restated our unsecured $150 million revolving credit facility. This agreement extended the termination date of the revolving credit facility from July 15, 2010 to January 26, 2013.

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, 2011, we are in compliance with these ratios. Our total indebtedness is 52.0% of our total capitalization as of June 30, 2011 and our EBITDA is 5.2 times our interest charges. 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, 2011. However, $18.5 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 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 Plaintiff crops due to inappropriate management of the levee system around Iatan, of which we are a 12% owner. Written discovery and depositions are now underway. This matter is set for trial beginning November 7, 2011, and we are unable to predict the outcome of the law suit.

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. On September 15, 2010, the parties agreed to a settlement in principle and on May 24, 2011, we, the Missouri Public Utility Alliance and the cities of Monett, Mt. Vernon and Lockwood, Missouri filed a Settlement Agreement and Offer of Settlement with the FERC. We expect to refund approximately $1.2 million as a result of this settlement.

Coal, Natural Gas and Transportation Contracts

(in millions)	Firm physical gas and transportation contracts		Coal and coal transportation contracts
July 1, 2011 through December 31, 2011	$	24.0	$	21.2
January 1, 2012 through December 31, 2013	56.9		57.0
January 1, 2014 through December 31, 2015	29.4		36.9
January 1, 2016 and beyond	25.8		15.9

18

In addition to the above, we have signed an agreement with Southern Star Central Pipeline, Inc. to purchase one million Dths of firm gas storage service capacity for our electric business for a period of five years which began in April 2011. The reservation charge for this storage capacity is approximately $1.1 million annually.

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 detailed in the table above.

We have coal supply agreements and transportation contracts in place to provide for the delivery of coal to the plants. These contracts are written with Force Majeure clauses that enable us to reduce tonnages or cease shipments under certain circumstances or events. These include mechanical or electrical maintenance items, acts of God, war or insurrection, strikes, weather and other disrupting events. This reduces the risk we have for not taking the minimum requirements of fuel under the contracts. The minimum requirements for our coal and coal transportation contracts are detailed in the table above.

Purchased Power

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

We have a long-term (30 year) agreement for the purchase of capacity from the Plum Point Energy Station, a 665-megawatt, coal-fired generating facility operated by North America Energy Services near Osceola, Arkansas which met its in-service criteria on August 13, 2010. We began receiving purchased power on September 1, 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 $39.6 million through August 30, 2015.

We have a 20-year purchased power agreement, which began on December 15, 2008, with Cloud County Windfarm, LLC, owned by EDP Renewables North America LLC (formerly 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. We also have a 20-year contract with Elk River Windfarm, LLC, owned by IBERDROLA RENEWABLES, Inc., to purchase the energy generated at the 150-megawatt Elk River Windfarm located in Butler County, Kansas. Although these agreements are considered operating leases under GAAP, payments for these 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

We purchased an undivided ownership interest in the coal-fired Iatan 2 generating facility operated by Kansas City Power & Light Company (KCP&L) and located at the site of the existing Iatan Generating Station (Iatan 1) near Weston, Missouri. We own 12%, or approximately 102 megawatts, of the 850-megawatt unit, which met its in-service criteria on August 26, 2010 and entered commercial operation on December 31, 2010. Our share of the Iatan 2 construction costs are expected to be in a range of approximately $237 million to $240 million, excluding AFUDC. Our share of the Iatan 2 costs through June 30, 2011 was $232.2 million plus AFUDC of $19.1 million. Current projections estimate $7.8 million being spent during the remainder of 2011 for our remaining share of expected expenditures for Iatan 2. These construction costs will be subject to prudency reviews by our regulators. We have requested or been granted recovery with respect to certain of these costs as set forth in the following section.

19

Recovery of construction costs

On September 28, 2010, we filed a rate increase request with the MPSC for an annual increase in base rates for our Missouri electric customers in the amount of $36.5 million, or 9.2% to recover the Iatan 2 costs and other cost of service items not included in our 2009 Missouri rate case that was effective September 10, 2010. A settlement agreement was filed on May 27, 2011, reflecting an overall annual increase in rates of $18.7 million, or approximately 4.7%. As part of the settlement, regulatory amortization expense of $14.5 million annually and construction accounting terminated as of June 15, 2011. The MPSC approved the settlement agreement on June 1, 2011 and the new rates became effective on June 15, 2011. The prudency of the construction costs for Iatan 1, Iatan 2 and Plum Point was not addressed in this case but may be considered in a future rate proceeding.

On August 30, 2010, we were granted a two-phase Capital Reliability Rider (CRR) by the Oklahoma Corporation Commission (OCC) with the first phase effective September 1, 2010. In total, the CRR revenue has been specifically limited by the OCC to an overall annual revenue increase of $2.6 million, or 27.67% increase. The CRR revenue being collected is subject to refund/true-up in the next general rate case. On June 30, 2011, we filed a request with the OCC for an annual increase in base rates for our Oklahoma electric customers (which would replace the CRR with permanent rates) in the amount of $0.6 million, or 4.1%, over the base rate and CRR revenues that are currently in effect.

A stipulated agreement in our 2009 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 are deferring depreciation and operating and maintenance expense on both Plum Point and Iatan 2 from their respective in-service dates until the effective date of the rates from the next Kansas case, which was filed on June 17, 2011 as an abbreviated case seeking a rate increase of $1.5 million, or 6.39%. This case includes a request to recover the Iatan and Plum Point cost deferrals over a 3 year period.

On August 19, 2010, we filed a rate increase request with the Arkansas Public Service Commission (APSC) for an annual increase in base rates for our Arkansas electric customers in the amount of $3.2 million, or 27.3%. On February 2, 2011 we entered into a unanimous settlement agreement with the parties involved. The settlement includes a general rate increase of $2.1 million, or 19%. The APSC approved the settlement on April 12, 2011 with the new rates effective April 13, 2011.

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 agreements are disclosed in the Purchased Power section of this note.

We also currently have short-term operating leases for two unit trains to meet coal delivery demands, for garage and office facilities for our electric segment and for one office facility related to our gas segment. In addition, we have capital leases for certain office equipment and 108 railcars to provide coal delivery for our ownership and purchased power agreement shares of the 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 any such costs to be material, although recoverable in rates.

20

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 pollutants (HAPs) and so-called greenhouse gases (GHG) such as carbon dioxide (CO2) and methane.

Permits

Under the CAA we have obtained, and renewed as necessary, site operating permits, which are valid for five years, for each of our plants.

SO2 Emissions

The CAA regulates the amount of SO2 an affected unit can emit. Currently SO2 emissions are limited by the Title IV Acid Rain Program and the Clean Air Interstate Rule (CAIR). In 2012, CAIR will be replaced by the Cross-State Air Pollution Rule (CSAPR- formerly the Clean Air Transport Rule) however; the Title IV Acid Rain Program will still remain in effect.

The Power Plant Mercury and Air Toxics Standards Rule (Toxics Rule), discussed below, will become effective November 16, 2014 and will affect SO2 emission rates at our facilities. In addition, the compliance date for existing sources with the revised SO2 National Ambient Air Quality Standards (NAAQS) is August of 2017, which will also affect SO2 emissions. The SO2 NAAQS is discussed in more detail below.

Title IV Acid Rain Program:

Under the Title IV Acid Rain Program, each existing affected unit has been allocated a specific number of emission allowances by the U.S. Environmental Protection Agency (EPA).  Each allowance 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 2010, our SO2 emissions exceeded the annual allocations. This deficit was covered by our banked allowances. When our Title IV Acid Rain Program SO2 allowance bank is exhausted, currently estimated to be early 2012, we will need to purchase additional SO2 allowances, blend more low sulfur coal at our facilities or fuel switch to natural gas at our coal-fired Riverton Units 7 and 8. The longer term solution may be some combination of the above until a Flue Gas Desulphurization (FGD) scrubber system at our Asbury Plant can be constructed. We expect the cost of compliance to be fully recoverable in our rates.

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/or NOx in 28 eastern states and the District of Columbia, including Missouri, where our Asbury, Energy Center, State Line and Iatan Units No. 1 and No. 2 are located. Kansas was not included in CAIR and our Riverton Plant was not affected. Arkansas, where our Plum Point Plant is located, was included for ozone season NOx but not for SO2.

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 and required covered states to develop State Implementation Plans (SIPs) to comply with specific SO2 state-wide annual budgets.

SO2 allowance allocations under the Title IV Acid Rain Program are used for compliance in the CAIR SO2 Program. Beginning in 2010, SO2 allowances were utilized at a 2:1 ratio for our

21

Missouri units. As a result, based on current SO2 allowance usage projections, we expect to have sufficient allowances to take us up to the beginning of the CSAPR program, which replaces CAIR and is set to begin January 1, 2012 (CSAPR is discussed in more detail below).

In order to meet CAIR requirements for SO2 and NOx emissions (NOx is discussed below in more detail) and as a requirement for the air permit for Iatan 2, a Selective Catalytic Reduction system (SCR), a FGD scrubber system and baghouse were installed at our jointly-owned Iatan 1 plant and a SCR was installed at our Asbury plant in 2008. Our jointly-owned Iatan 2 and Plum Point plants were originally constructed with the above technology.

CSAPR- formerly the Clean Air Transport Rule:

On July 6, 2010, the EPA published a proposed CAIR replacement rule entitled the Clean Air Transport Rule (CATR). As proposed and supplemented, the CATR included Missouri and Kansas under both the annual and ozone season for NOx as well as the SO2 program while Arkansas remained in the ozone season NOx program only. The final CATR was released on July 7, 2011 under the name of the CSAPR, and becomes effective January 1, 2012. The final rule requires a 73% reduction in SO2 from 2005 levels by 2014. The SO2 allowances allocated under the EPA’s Title IV Acid Rain Program cannot be used for compliance with CSAPR but will continue to be used for compliance with the Title IV Acid Rain Program. Therefore, new SO2 allowances will be allocated under CSAPR and will be retired at one allowance per ton of SO2 emissions emitted. We will receive fewer SO2 allowances than we currently emit. Compliance options range from purchasing additional emission allowances to using more low sulfur coal to installing a FGD scrubber at our Asbury facility (see estimated construction costs below) and potential forced retirement or fuel switching to natural gas of our coal-fired Riverton Units 7 and 8. We expect compliance costs to be recoverable in our rates.

Toxics Rule

Proposed by EPA on March 16, 2011 and scheduled to take effect November 16, 2011, this regulation does not include allowance mechanisms, but would establish alternative standards for certain pollutants, including SO2 (as a surrogate for hydrogen chloride (HCI)), which must be met to show compliance with hazardous air pollutant limits (see additional discussion in the Toxics Rule section below).

SO2 National Ambient Air Quality Standard (NAAQS):

In June 2010, the EPA finalized a new one hour SO2 NAAQS which, for areas with no SO2 monitor, will require modeling to determine attainment and non-attainment areas within each state. This modeling of emission sources is to be completed by June 2013 with compliance with the SO2 NAAQS required by August 2017. States are awaiting modeling guidance from the EPA. It is likely coal-fired generating units will need scrubbers to be capable of meeting the new one hour SO2 NAAQS.

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. Currently revised NOx emissions are limited by the CAIR and will be limited by the CSAPR beginning in 2012 and ozone NAAQS rules which are scheduled to be issued by the end of 2011.

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 NOx in 28 states, including Missouri, where our Asbury, Energy Center, State Line and Iatan Units No. 1 and No. 2 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.

22

The CAIR required covered states to develop SIPs to comply with specific annual NOx state-wide allowance allocation budgets. Based on existing State SIPs, we had excess NOx allowances during 2010 which were banked for future use and will be sufficient for compliance through the end of the CAIR program in 2011. The CAIR NOx program will also be replaced by the CSAPR program January 1, 2012.

CSAPR:

The final rule requires a 54% reduction in NOx from 2005 levels by 2014. The NOx annual and ozone season allowances that were allocated and banked under CAIR cannot be used for compliance under CSAPR.  New allowances will be issued under CSAPR.

To address NOx annual and NOx ozone season compliance, options range from increasing the level of control with the Asbury SCR, fuel switching to natural gas at our Riverton Plant coal-fired units, or purchasing emission allowances. We expect the cost of compliance to be fully recoverable in our rates.

Ozone NAAQS:

Ozone, also called ground level smog, is formed by the mixing of NOx and Volatile Organic Compounds (VOCs) in the presence of sunlight. On January 6, 2010, the EPA proposed to lower the primary NAAQS for ozone designed to protect public health to a range between 60 and 70 ppb and to set a separate secondary NAAQS for ozone designed to protect sensitive vegetation and ecosystems. The EPA has delayed publication of the final standards until mid-August 2011 or later. Until the EPA finalizes the proposed standard, states will continue to identify and designate all non-attainment areas based on the 2008, 75 ppb standard.

Toxics Rule

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.

The EPA issued an Information Collection Request (ICR) for determining the National Emission Standards for Hazardous Air Pollutants (NESHAP), including mercury, for coal and oil-fired electric steam generating units on December 24, 2009. This ICR included our Iatan, Asbury and Riverton plants. All ICRs were submitted as required. The EPA ICR was intended for use in developing regulations under Section 112(r) of the CAA maximum achievable emission standards for the control of the emission of HAPs, including mercury. The EPA proposed the first ever national mercury and air toxics standards (Power Plant Mercury and Air Toxics Standards Rule) in March 2011. It would establish numerical emission limits to reduce emissions of heavy metals, including mercury (Hg), arsenic, chromium, and nickel, and acid gases, including HCl and hydrogen fluoride (HF). For all existing and new coal-fired electric utility steam generating units (EGUs), the proposed standard will be phased in over three years, and allows states the ability to give facilities a fourth year to comply.

Absent a successful legal challenge or changes to applicable legislation, we expect the Toxics Rule regulation of HAPs in combination with CSAPR to ultimately require a scrubber, baghouse and powder activated carbon injection system to be added to our Asbury facility at a cost ranging from $120 million to $180 million and to force retirement of our Riverton coal-fired assets or a switch to natural gas fuel. Our Riverton coal-fired units were designed to combust either coal or natural gas. We expect compliance costs to be recoverable in our rates.

23

Green House Gases

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 that equal or exceed an emission threshold of 25,000 metric tons of CO2e to report GHGs to the EPA annually commencing in September 2011. We will report our GHG emissions as required to the EPA in 2011 for EDE and EDG.

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 (Tailoring Rule) to address GHG emissions from stationary sources, which became effective January 2, 2011. The rule 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 covered sources. Under the PSD program, required controls for GHG emissions would be determined based on Best Available Control Technology (BACT). EPA issued a BACT permitting guidance document on November 11, 2010. Missouri and Kansas have been delegated GHG permitting authority by EPA. Several parties have filed petitions with the EPA and lawsuits have been filed challenging the EPA’s Endangerment Finding and the Tailoring Rule.

In addition, on December 23, 2010 the EPA entered into an agreement with a number of state and environmental petitioners to settle litigation pending in the U.S. Court of Appeals for the District of Columbia Circuit that requires EPA to propose New Source Performance Standards (NSPS) for GHGs for fossil-fuel fired steam generating units by September 30, 2011 and to issue final GHG NSPS standards by May 26, 2012.

A variety of proposals have been and are likely to continue to be considered by Congress to reduce GHGs. Proposals are also being considered in the House and Senate that would delay, limit or eliminate EPA’s authority to regulate GHGs. At this time, it is not possible to predict what legislation, if any, will ultimately emerge from Congress regarding control of GHGs.

Certain states have taken steps to develop cap and trade programs and/or other regulatory systems which may be more stringent than federal requirements. 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 Units 7 and 8 and Iatan Unit 1, which utilize once-through cooling water, were 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 submitted 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. KCP&L, who operates Iatan Unit 1, submitted the appropriate sampling and summary reports to the Missouri Department of Natural Resources (MDNR). 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 revised and

24

signed a pre-publication proposed regulation on March 28, 2011 and is obligated to finalize the rule by July 27, 2012.

We will not know the full impact of these rules until they are finalized. If adopted in their present form, we expect regulations of Cooling Water Intake Structures issued by the EPA under the CWA Section 316(b) to have an impact at Riverton ranging from minor improvements to the cooling water intake structure to retirement of units 7 and 8. Impacts at Iatan 1 could range from flow velocity reductions or traveling screen modifications for fish handling to installation of a closed cycle cooling tower retrofit. Our new Iatan Unit 2 and Plum Point Unit 1 are covered by the proposed regulation but were constructed with cooling towers, the proposed Best Technology Available. We expect them to be unaffected or minimally impacted by the final rule.

Surface Impoundments

We own and maintain coal ash impoundments located at our Riverton and Asbury Power Plants. Additionally, we own a 12 percent interest in a coal ash impoundment at the Iatan Generating Station and a 7.52% interest in a coal ash impoundment at Plum Point. 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 impoundments. We do not have sufficient information at this time to estimate additional costs that might result from any new standards. All of the coal ash impoundments are compliant with existing state and federal regulations.

On June 21, 2010, the EPA proposed a 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. The public comment period closed in November 2010. It is anticipated that the final regulation will be published in late 2011 or in 2012. We expect compliance with either option as proposed 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) at a potential cost of up to $15 million at our Asbury and Riverton Power Plants. This preliminary estimate will likely change based on the final CCR rule and its requirements. We expect resulting costs to be recoverable in our rates.

On September 23, 2010 and on November 4, 2010 representatives from GEI Consultants, on behalf of the EPA, conducted on-site inspections of our Riverton and Asbury coal ash impoundments, respectively. The consultants performed a visual inspection of the impoundments to assess the structural integrity of the berms surrounding the impoundments, requested documentation related to construction of the impoundments, and reviewed recently completed engineering evaluations of the impoundments and their structural integrity. We received final reports on the Asbury and the Riverton impoundments on July 28, 2011 and July 26, 2011, respectively. We are reviewing the reports and are required to respond to the reports’ recommendations by August 29, 2011.

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 us and other investor-owned utilities in Missouri to generate or purchase electricity from renewable energy sources, such as solar, wind, biomass and hydro power, or purchase RECs, at the rate of at least 2% of retail sales by 2011, increasing to at least 15% by 2021.

25

Two percent of this amount must be solar. We believe we are exempted from the solar requirement. A challenge to our exemption, brought by two of our customers and Power Source Solar, Inc., was dismissed on May 31, 2011 by the Missouri Western District Court of Appeals. The plaintiffs have filed in the Missouri Supreme Court for transfer of the case from the Missouri Western District to the Missouri Supreme Court.

Renewable energy standard compliance rules were published by the MPSC on July 7, 2010.  On June 30, 2011, a Cole County Circuit Court judge ruled that portions of the MPSC rules were unlawful and unreasonable, in conflict with Missouri statute and in violation of the Missouri Constitution. We will comply with the portions of the rule left intact.

Kansas established a renewable portfolio standard (RPS), effective November 19, 2010. It requires 10% of our Kansas retail customer peak capacity requirements to be sourced from renewables by 2011, 15% by 2016, and 20% by 2020. 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.

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 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
	2011			2010			2011			2010			2011			2010
Service cost	$	1,404		$	1,273		$	27		$	17		$	507		$	509
Interest cost	2,612			2,550			51			39			1,062			1,063
Expected return on plan assets	(2,889		)	(2,483		)	—			—			(1,028		)	(966		)
Amortization of prior service cost (1)	133			133			(2		)	(2		)	(253		)	(253		)
Amortization of net actuarial loss (1)	1,395			1,033			52			32			381			344
Net periodic benefit cost	$	2,655		$	2,506		$	128		$	86		$	669		$	697

	Six months ended June 30,
	Pension Benefits						SERP						OPEB
	2011			2010			2011			2010			2011			2010
Service cost	$	2,798		$	2,546		$	47		$	34		$	1,133		$	1,018
Interest cost	5,203			5,100			91			79			2,192			2,125
Expected return on plan assets	(5,569		)	(4,966		)	—			—			(2,078		)	(1,933		)
Amortization of prior service cost (1)	266			266			(4		)	(4		)	(505		)	(506		)
Amortization of net actuarial loss (1)	2,747			2,067			85			63			881			689
Net periodic benefit cost	$	5,445		$	5,013		$	219		$	172		$	1,623		$	1,393

26

	Twelve months ended June 30,
	Pension Benefits						SERP						OPEB
	2011			2010			2011			2010			2011			2010
Service cost	$	5,139		$	5,148		$	83		$	65		$	2,253		$	1,885
Interest cost	10,218			10,047			166			152			4,396			3,980
Expected return on plan assets	(10,450		)	(10,143		)	—			—			(3,990		)	(3,845		)
Amortization of prior service cost (1)	531			568			(8		)	(8		)	(1,011		)	(1,011		)
Amortization of net actuarial loss (1)	4,676			3,658			118			115			1,691			970
Net periodic benefit cost	$	10,114		$	9,278		$	359		$	324		$	3,339		$	1,979

(1) Amounts are amortized from our regulatory asset originally recorded upon recognizing our net pension liability on the balance sheet.

Annual contributions to our pension plans are at least equal to the minimum funding requirements of ERISA. Beginning in 2010, we were also required to fund at least our actuarial cost in accordance with our regulatory agreements. On March 29, 2011, we made a $13.5 million contribution to our Pension Trust, on April 13, 2011, we made an additional $2.1 million contribution and on July 14, 2011, we made a $2.1 million quarterly contribution. We estimate an additional quarterly contribution of approximately $2.1 million will be required in October 2011. The actual minimum funding requirements will be determined based on the results of the actuarial valuations and, in the case of 2012, the performance of our pension assets during 2011. Our OPEB funding policy is to contribute annually an amount at least equal to the actuarial cost of postretirement benefits.

Note 9— Stock-Based Awards and Programs

Our performance based restricted stock awards, stock options and their related dividend equivalents are valued as liability awards, in accordance with fair value guidelines. Awards treated as liability instruments must be 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
	2011		2010		2011		2010		2011		2010
Compensation Expense	$	218	$	730	$	959	$	1,528	$	2,624	$	2,572
Tax Benefit Recognized	68		261		339		549		950		915

Activity for our various stock plans for the six months ended June 30, 2011 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:

27

	Fair Value of Grants Outstanding at June 30,
	2011	2010
Risk-free interest rate	0.11% to 0.60%	0.22% to 0.80%
Expected volatility of Empire stock	27.4%	28.6%
Expected volatility of peer group stock	20.8% to 82.2%	22.4% to 83.0%
Expected dividend yield on Empire stock	0.0% to 4.2%	7.0%
Expected forfeiture rates	3%	3%
Plan cycle	3 years	3 years
Fair value percentage	67.0% to 88.0%	124.0% to 152.0%
Weighted average fair value per share	$15.45	$26.21

Non-vested restricted stock awards (based on target number) as of June 30, 2011 and 2010 and changes during the six months ended June 30, 2011 and 2010 were as follows:

	2011				2010
	Number of shares		Weighted Average Grant Date Price		Number of shares		Weighted Average Grant Date Price
Nonvested at January 1,	47,500		$	19.86	52,200		$	21.57
Granted	10,900		$	21.84	13,000		$	18.36
Awarded	(39,621	)	$	21.92	(15,104	)	$	23.81
Awarded in Excess of Target	18,621		$	21.92
Not Awarded	—		—		(2,596	)	—
Nonvested at June 30,	37,400		$	19.28	47,500		$	19.86

At June 30, 2011, there was $0.2 million of total unrecognized compensation cost related to estimated outstanding awards. This cost will be recognized over the outstanding years remaining in the vesting period.

Stock Options

Stock 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, 2011 and 2010, under a Black-Scholes methodology. The assumptions used in the valuations are shown below:

	Fair Value of Grants Outstanding at June 30,
	2011	2010
Risk-free interest rate	0.25% to 1.77%	0.55% to 2.23%
Dividend yield	3.20% to 4.70%	7.0%
Expected volatility	24.0%	24.0%
Expected life in months	78	78
Market value	$  19.26	$  18.77
Weighted average fair value per option	$    1.55	$    1.05

	2011			2010
	Options	Weighted Average Exercise Price		Options	Weighted Average Exercise Price
Outstanding at January 1,	267,400	$	21.69	232,600	$	22.19
Granted	—	—		34,800	$	18.36
Exercised	77,100	$	22.02	—
Outstanding at June 30,	190,300	$	21.56	267,400	$	21.69
Exercisable at June 30,	128,500	$	23.15	149,200	$	23.04

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

28

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 table below shows the aggregate intrinsic values at June 30, 2011 and 2010:

	2011	2010
Aggregate intrinsic value (in millions)	less than $0.1	less than $0.1
Weighted-average remaining contractual life of outstanding options	5.6 years	6.6 years
Range of exercise prices	$18.12 to $23.81	$18.12 to $23.81
Total unrecognized compensation expense (in millions) related to non-vested options and related dividend equivalents granted under the plan	less than $0.1	$0.3
Recognition period	0.5 to 1.5 years	1 to 3 years

Beginning in 2011, we began issuing time-vested restricted stock in lieu of stock options.

Time-Vested Restricted Stock Awards

Beginning in 2011, time-vested restricted stock awards were granted to qualified individuals that vest after a three-year period. No dividend rights accumulate during the vesting period. Time-vested restricted stock is valued at an amount equal to the fair market value of our common stock on the date of grant. If employment terminates during the vesting period because of death, retirement, or disability, the participant is entitled to a pro-rata portion of the time-vested restricted stock awards such participant would otherwise have earned. If employment is terminated during the vesting period for reasons other than those listed above, the time-vested restricted stock awards will be forfeited on the date of the termination, unless the Board of Directors Compensation Committee determines, in its sole discretion, that the participant is entitled to a pro-rata portion of the award.

On February 2, 2011, shares of time-vested restricted stock were granted to qualified individuals at the fair market value per the table below:

	2011
	Number of shares	Grant Date Price
Outstanding at January 1,	—	$	—
Granted	10,200	$	21.84
Vested	—	—
Outstanding at June 30,	10,200	$	21.84

All time-vested restricted stock awards are classified as liability instruments, which must be revalued each period until settled. The cost of the awards is generally recognized over the requisite (explicit) service period.

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, 2011, there were 261,792 shares available for issuance in this plan.

	2011		2010
Subscriptions outstanding at June 30	72,182		72,874
Maximum subscription price	$	17.27	$	16.06
Shares of stock issued (1)	69,229		66,723
Stock issuance price	$	16.06	$	14.62

(1) Stock will be issued on the closing date of the purchase period, which runs from June 1, 2011 to May 31, 2012.

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

29

	ESPP
	2011			2010
Weighted average fair value of grants	$	3.17		$	2.28
Risk-free interest rate	0.18		%	0.35		%
Dividend yield	2.60		%	7.20		%
Expected volatility	22.00		%	17.00		%
Expected life in months	12			12
Grant Date	6/1/11			6/1/10

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
	2011			2010		2011		2010		2011		2010
Electric transmission and distribution expense	$	3,418		$	3,144	$	7,240	$	5,971	$	14,265	$	11,697
Natural gas transmission and distribution expense	579			515		1,141		1,046		2,289		2,133
Power operation expense (other than fuel)	2,469			2,791		5,147		5,695		10,807		11,884
Customer accounts and assistance expense	2,395			2,998		4,931		5,917		10,632		11,326
Employee pension expense (1)	1,975			1,287		3,819		2,751		6,967		5,622
Employee healthcare plan (1)	1,716			1,696		3,337		3,246		7,022		6,463
General office supplies and expense	2,236			2,705		5,135		5,381		11,338		10,626
Administrative and general expense	3,057			3,218		6,704		6,634		12,966		12,995
Allowance for uncollectible accounts	1,242			855		1,324		1,455		3,520		2,780
Miscellaneous expense	(2		)	63		23		93		98		172
Total	$	19,085		$	19,272	$	38,801	$	38,189	$	79,904	$	75,698

(1) Does not include capitalized portion of costs, but reflects the GAAP expensed cost plus or minus costs deferred to and amortized from a regulatory asset and/or 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, 2011
	Electric		Gas			Other		Eliminations			Total
($-000’s)
Statement of Operations Information
Revenues	$	120,329	$	7,303		$	1,609	$	(148	)	$	129,093
Depreciation and amortization	15,582		870			436		—			16,888
Federal and state income taxes	5,340		(13		)	252		—			5,579
Operating income	17,795		928			411		—			19,134
Interest income	16		58			—		(58		)	16
Interest expense	9,017		978			1		(58		)	9,938
Income from AFUDC (debt and equity)	128		—			—		—			128
Net income	8,792		(27		)	410		—			9,175
Capital Expenditures	$	33,034	$	694		$	1,081				$	34,809

30

	For the quarter ended June 30, 2010
	Electric		Gas			Other		Eliminations			Total
($-000’s)
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

	For the six months ended June 30, 2011
	Electric		Gas		Other		Eliminations			Total
($-000’s)
Statement of Operations Information
Revenues	$	248,690	$	28,292	$	3,135	$	(296	)	$	279,821
Depreciation and amortization	31,610		1,743		868		—			34,221
Federal and state income taxes	10,973		1,368		483		—			12,824
Operating income	36,071		4,122		788		—			40,981
Interest income	38		130		—		(128		)	40
Interest expense	17,818		1,954		4		(128		)	19,648
Income from AFUDC (debt and equity)	151		—		—		—			151
Net income	18,093		2,219		785		—			21,097
Capital Expenditures	$	49,885	$	1,034	$	1,448				$	52,367

	For the six months ended June 30, 2010
	Electric		Gas		Other		Eliminations			Total
($-000’s)
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

31

	For the twelve months ended June 30, 2011
	Electric		Gas		Other		Eliminations			Total
($-000’s)
Statement of Operations Information
Revenues	$	512,686	$	48,101	$	6,526	$	(592	)	$	566,721
Depreciation and amortization	60,919		3,436		1,751		—			66,106
Federal and state income taxes	26,120		1,767		1,051		—			28,938
Operating income	82,725		6,672		1,722		—			91,119
Interest income	103		273		—		(282		)	94
Interest expense	35,908		3,926		15		(282		)	39,567
Income from AFUDC (debt and equity)	1,814		12		—		—			1,826
Net income	47,951		2,879		1,707		—			52,537
Capital Expenditures	$	96,148	$	5,389	$	2,258				$	103,795

	For the twelve months ended June 30, 2010
	Electric		Gas		Other		Eliminations			Total
($-000’s)
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

As of June 30, 2011

	Electric		Gas(1)		Other		Eliminations			Total
($-000’s)
Balance Sheet Information
Total assets	$	1,854,569	$	140,712	$	24,349	$	(88,647	)	$	1,930,983

(1) Includes goodwill of $39,492.

As of December 31, 2010

	Electric		Gas(1)		Other		Eliminations			Total
($-000’s)
Balance Sheet Information
Total assets	$	1,837,910	$	139,532	$	23,163	$	(79,294	)	$	1,921,311

(1) Includes goodwill of $39,492.

Note 12— Income Taxes

The following table shows the changes in our provision for income taxes (in millions) and our consolidated effective federal and state income tax rates for the applicable periods ended June 30, 2011:

32

	Three Months Ended						Six-Months Ended						Twelve Months Ended
	2011			2010			2011			2010			2011			2010
Consolidated provision for income taxes	$	5.6		$	4.5		$	12.8		$	14.4		$	28.9		$	24.6
Consolidated effective federal and state income tax rates	37.8		%	37.7		%	37.8		%	47.5		%	35.5		%	38.9		%

The effective tax rates for the six months ended June 30, 2011 and the twelve months ended June 30, 2011 are lower than comparable year periods primarily due to an adjustment made in 2010 as a result of the Patient Protection and Affordable Care Act, which became law on March 23, 2010. This legislation included a provision that reduced the deductibility, for income tax purposes, of retiree healthcare costs to the extent an employer receives federal subsidies. Although the elimination of this tax benefit does not take effect until 2013, this change required us to recognize the full accounting impact in our financial statements in the period in which the legislation was 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, which increased our effective tax rate in 2010 and our 2010 provision for income taxes.

As part of an agreement reached in our 2009 Missouri electric rate case, effective September 10, 2010, we also agreed to commence an eighteen year amortization of a regulatory 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 had recorded the regulatory asset expecting to recover these benefits from customers in future periods. Based on the agreement, 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.

We received $26.6 million in 2010 from the SWPA which has been deferred for book purposes and treated as a noncurrent liability and is more fully described in our Annual Report on Form 10-K for the year ended December 31, 2010. We increased our current tax liability by $10.0 million in recognition that the $26.6 million payment may be considered taxable income in 2010. During the first quarter of 2011, we submitted a pre-filing agreement with the Internal Revenue Service (IRS) requesting that a determination be made regarding whether or not the payment could be deferred under certain sections of the Internal Revenue code. The IRS is still reviewing our request.

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, 2010 was $359,000 and has not materially changed at June 30, 2011.

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 2011, 90.5% of our gross operating revenues were provided from sales from our electric segment (including 0.3% from the sale of water), 8.5% from our gas segment and 1.0% from our other segment.

Earnings

During the second quarter of 2011, basic and diluted earnings per weighted average share of common stock were $0.22 as compared to $0.18 in the second quarter of 2010. For the six months ended June 30, 2011, basic and diluted earnings per weighted average share of common stock were

33

$0.51 as compared to $0.40 for the six months ended June 30, 2010. For the twelve months ended June 30, 2011, basic and diluted earnings per weighted average share of common stock were $1.26 as compared to $1.03 for the twelve months ended June 30, 2010. The primary positive drivers for all periods presented were increased electric revenues (due primarily to rate increases) and decreased interest charges. The six and twelve month periods also benefited significantly from the change in effective tax rates when compared to 2010 when we had two non-cash charges in the first quarter of 2010 that negatively impacted our effective tax rates. (See Note 12 of “Notes to Consolidated Financial Statements (Unaudited)”). The primary negative drivers for all periods presented were changes in AFUDC amounts due to the completion of our construction program and increased depreciation and amortization amounts. The six and twelve month ending periods were also negatively impacted by higher operations and maintenance expenses, as well as the dilutive effect of additional shares issued. A portion of the increase in depreciation and amortization expense reflects the effect of additional regulatory amortization collected in revenues in our Missouri rate case effective September 2010 (which regulatory amortization expense was terminated effective June 15, 2011).

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, 2010 and June 30, 2011, 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			Six Months			Twelve Months
	Ended			Ended			Ended
Earnings Per Share — 2010	$	0.18		$	0.40		$	1.03
Revenues
Electric on-system	$	0.19		$	0.39		$	1.04
Electric off-system and other	0.02			0.06			0.14
Gas	0.01			(0.04		)	(0.08		)
Other	—			—			0.01
Expenses
Electric fuel and purchased power	(0.05		)	(0.10		)	(0.30		)
Cost of natural gas sold and transported	(0.01		)	0.04			0.09
Regulated — electric segment	—			(0.03		)	(0.10		)
Regulated —gas segment	—			0.02			0.02
Maintenance and repairs	(0.01		)	(0.04		)	(0.09		)
Depreciation and amortization	(0.05		)	(0.12		)	(0.23		)
Other taxes	(0.01		)	(0.03		)	(0.06		)
Interest charges	0.02			0.05			0.11
AFUDC	(0.06		)	(0.13		)	(0.24		)
Change in effective income tax rates	—			0.07			0.05
Dilutive effect of additional shares issued	(0.01		)	(0.03		)	(0.13		)
Earnings Per Share — 2011	$	0.22		$	0.51		$	1.26

34

Recent Activities

Tornado and Dividend Suspension

On May 22, 2011, a devastating tornado hit the Joplin, Missouri area damaging or destroying thousands of homes and businesses. Shortly following the storm, we estimated that approximately 8,000 to 10,000 of our residential, commercial and industrial customers had damaged or destroyed structures that would not be ready for service in the foreseeable future, resulting in a significant loss of revenue, estimated at that time to be approximately 10 to 15 percent of our summer peak load (assuming normal weather).

During the weeks following the tornado, restoration efforts have resulted in the return to service of several thousand of our customers. We currently estimate that approximately 4,200 customers remain unable to return to service due to damaged or destroyed structures. Restoration activities partially mitigated the impact of some of our load loss as tornado victims and outside volunteers needing housing occupied hotels, rental properties and some temporary structures during much of June.

We estimate that the net impact of the tornado on our sales and revenues (after adjusting for weather) was a 3% reduction in kWh sales and a $2.2 million reduction in revenues during the second quarter of 2011 as compared to 2010.

We still expect a continuing loss of electric load and corresponding revenues over the next several months as customers rebuild, including one of our local hospitals and several other commercial customers. We also anticipate a gradual decline of outside volunteers that have occupied local hotels in recent weeks. The remaining restoration and timing remain uncertain in the short term.

In response to this expected loss of revenues, our current level of retained earnings and other relevant factors, our Board of Directors suspended our quarterly dividend for the third and fourth quarters of 2011. Based on current conditions and knowledge, the Board of Directors expects to re-establish the dividend at an approximate level of $0.25 per quarter after this two quarter suspension.

We currently estimate the cost of storm restoration to be in the $20 million to $30 million range. As of June 30, 2011, approximately $18 million of restoration costs had been recorded, the majority of which was capitalized. Our estimate includes approximately $8 million for one of our substations which was destroyed, most of which we expect to be covered by insurance. No costs have been incurred thus far on the substation. In addition, we still have distribution lines that were destroyed but have not been replaced. The remaining cost is expected to be absorbed into our existing capital expenditure plan.

On June 6, 2011, we filed an Accounting Authority Order with the MPSC requesting authorization to defer expenses associated with the tornado and to allow for recovery of the loss of the fixed cost component included in our rates resulting from the lost sales. On June 23, 2011, Praxair, Inc. and Explorer Pipeline Company filed as intervenors with the MPSC, who granted their request on July 6, 2011. The order is still pending.

Coal Conservation related to Missouri River Flooding

The Iatan plant, located along the Missouri River north of Kansas City and operated by Kansas City Power & Light (“KCP&L”), has been impacted by recent flooding in the Midwest. Beginning June 30, 2011 coal deliveries to Iatan were suspended. While it is not possible to predict with certainty how long the suspension will continue, KCP&L management currently expects coal deliveries at Iatan to resume in September. As a result, in early July it was decided to begin operating Iatan Units 1 and 2 at reduced loads in an effort to conserve coal. Additionally, we entered into a short term purchase of power for the month of August to address a portion of the lost generation from the Iatan units. We would expect that any additional fuel and purchased power costs incurred as a result of this event would be recovered in our rates through fuel recovery mechanisms.

Amendment of EDE Mortgage

On June 9, 2011, we amended the Indenture of Mortgage and Deed of Trust of The Empire District Electric Company (EDE Mortgage) in order to provide us with additional flexibility to pay

35

dividends to our shareholders by permitting the payment of any dividend or distribution on, or purchase of, shares of its common stock within 60 days after the related date of declaration or notice of such dividend, distribution or purchase if (i) on the date of declaration or notice, such dividend, distribution or purchase would have complied with the provisions of the indenture and (ii) as of the last day of the calendar month ended immediately preceding the date of such payment, our ratio of total indebtedness to total capitalization (after giving pro forma effect to the payment of such dividend, distribution, or purchase) was not more than 0.625 to 1. The amendment followed the successful completion of a solicitation of consents from the holders of our First Mortgage Bonds outstanding under the EDE Mortgage. We received consents from holders of 73.91% in aggregate principal amount of the outstanding bonds and paid consent fees of approximately $0.8 million. See “Dividends” below.

Financings

On January 28, 2011, we filed a $400 million shelf registration statement with the SEC covering our common stock, unsecured debt securities, preference stock, and first mortgage bonds. This shelf registration statement became effective on February 7, 2011. We plan to use proceeds under this shelf to fund capital expenditures, refinancings of existing debt or general corporate needs during the effective period. The issuance of securities under this shelf is subject to the receipt of local regulatory approvals. We have received regulatory approval from Kansas and Oklahoma but are awaiting approvals from the remaining states in our electric service territory.

Regulatory Matters

A settlement agreement among the parties to our Missouri rate case filed on September 28, 2010 was reached and filed with the MPSC on May 27, 2011, reflecting an overall annual increase in rates of $18.7 million, or approximately 4.7%, to become effective on June 15, 2011. As part of the settlement, regulatory amortization expense of $14.5 million annually and construction accounting terminated on June 15, 2011. The MPSC approved the settlement agreement on June 1, 2011 and the new rates became effective on June 15, 2011.

On June 17, 2011, we filed an application with the Kansas Corporation Commission (KCC) seeking a rate increase of $1.5 million, or 6.39%. The rate increase is being requested to recover the costs associated with our investment in the Iatan 1, Iatan 2 and Plum Point generating units and the depreciation and operation and maintenance costs deferred since the in-service dates of the units. The June 17, 2011 filing was made under the KCC’s abbreviated rate case rules which the KCC authorized in our 2009 Kansas rate case. The case includes a request to recover the Iatan and Plum Point cost deferrals over a 3-year period.

On June 30, 2011, we filed a request with the Oklahoma Corporation Commission (OCC) for an annual increase in base rates for our Oklahoma electric customers in the amount of $0.6 million, or 4.1% over the base rate and Capital Reliability Rider (CRR) revenues that are currently in effect.

On February 2, 2011 we entered into a unanimous settlement agreement with the parties involved in our Arkansas rate case filed August 19, 2010. The settlement includes a general rate increase of $2.1 million, or 19%. The APSC approved the settlement on April 12, 2011 with the new rates effective April 13, 2011.

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. On September 15, 2010, the parties agreed to a settlement in principle and on May 24, 2011, we, the Missouri Public Utility Alliance and the cities of Monett, Mt. Vernon and Lockwood, Missouri filed a Settlement Agreement and Offer of Settlement with the FERC. We expect to refund approximately $1.2 million as a result of this settlement.

For additional information on all these cases, see “Rate Matters” below.

36

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, 2011, compared to the same periods ended June 30, 2010.

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
	2011		2010			2011		2010		2011		2010
Electric	$	8.8	$	7.4		$	18.1	$	13.3	$	47.9	$	35.5
Gas	—		(0.4		)	2.2		2.0		2.9		1.8
Other	0.4		0.4			0.8		0.7		1.7		1.4
Net income	$	9.2	$	7.4		$	21.1	$	16.0	$	52.5	$	38.7

*Differences could occur due to rounding.

Electric Segment

Overview

Our electric segment income for the second quarter of 2011 was $8.8 million as compared to $7.4 million for the second quarter of 2010, an increase of $1.4 million, primarily due to the September 2010 Missouri rate increase, the July 2010 Kansas rate increase, the September 2010 and March 2011 Oklahoma rate increases and the April 2011 Arkansas rate increase (discussed below).

Electric operating revenues comprised approximately 92.9% of our total operating revenues during the second quarter of 2011. Electric operating revenues for the second quarter of 2011 and 2010 were comprised of the following:

	2011		2010
Residential	38.5	%	38.0	%
Commercial	31.7		32.7
Industrial	16.6		16.1
Wholesale on-system	3.8		4.3
Wholesale off-system	5.0		4.8
Miscellaneous sources*	2.7		2.6
Other electric revenues	1.7		1.5

*primarily public authorities

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	2011	2010	Change*		2011	2010	Change*		2011	2010	Change*
Residential	399.4	396.3	0.8	%	990.8	1,035.6	(4.3	)%	2,015.6	1,963.9	2.6	%
Commercial	384.5	405.6	(5.2	)	760.2	791.3	(3.9	)	1,613.9	1,591.2	1.4
Industrial	262.6	259.4	1.2		499.6	490.4	1.9		1,016.3	990.3	2.6
Wholesale on-system	88.7	85.4	3.9		176.3	170.3	3.5		361.8	338.9	6.8
Other**	30.8	29.5	4.4		64.1	63.3	1.1		127.1	124.8	1.9
Total on-system sales	1,166.0	1,176.2	(0.9	)	2,491.0	2,550.9	(2.3	)	5,134.7	5,009.1	2.5
Off-system	195.1	213.3	(8.5	)	453.0	395.8	14.4		855.3	666.0	28.4
Total KWh Sales	1,361.1	1,389.5	(2.0	)	2,944.0	2,946.7	(0.1	)	5,990.0	5,675.1	5.5

*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.

37

Electric Segment Operating Revenues

($ in millions)

	Second		Second				6 Months		6 Months				12 Months		12 Months
	Quarter		Quarter		%		Ended		Ended		%		Ended		Ended		%
Customer Class	2011		2010		Change*		2011		2010		Change*		2011		2010		Change*
Residential	$	46.2	$	40.4	14.3	%	$	105.5	$	94.4	11.8	%	$	216.1	$	186.7	15.7	%
Commercial	38.0		34.8		9.4		72.3		64.5		12.1		154.1		135.4		13.8
Industrial	19.9		17.1		16.2		36.5		31.2		17.2		75.1		65.5		14.6
Wholesale on-system	4.5		4.5		(0.3	)	8.8		9.5		(7.6	)	18.5		18.7		(0.7	)
Other**	3.3		2.8		17.8		6.6		5.6		16.4		13.2		11.7		12.8
Total on-system revenues	$	111.9	$	99.6	12.3		$	229.7	$	205.2	12.0		$	477.0	$	418.0	14.1
Off-system	6.0		5.1		19.1		14.0		11.3		23.9		25.6		19.1		34.3
Total revenues from kWh sales	117.9		104.7		12.7		243.7		216.5		12.6		502.6		437.1		15.0
Miscellaneous revenues***	2.0		1.6		25.2		4.1		3.3		22.1		8.3		6.9		20.0
Total electric operating revenues	$	119.9	$	106.3	12.9		$	247.8	$	219.8	12.7		$	510.9	$	444.0	15.1
Water revenues	0.4		0.4		(2.4	)	0.9		0.9		(2.0	)	1.8		1.7		0.7
Total electric segment operating revenues	$	120.3	$	106.7	12.8		$	248.7	$	220.7	12.7		$	512.7	$	445.7	15.0

*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.

We now have a fuel cost recovery mechanism in all of our jurisdictions, which significantly reduces the impact of fluctuating fuel costs on our net income. For this reason, we believe electric gross margin, although a non-GAAP measurement, is useful for understanding and analyzing changes in our electric operating performance from one period to the next. We define electric gross margins as electric revenues less fuel and purchased power costs.

The table below represents our electric gross margins for the applicable periods ended June 30 (in millions), which is a non-GAAP presentation. We believe this presentation is useful to investors and have included the analysis below as a complement to the financial information we provide in accordance with GAAP. However, these margins may not be comparable to other companies’ presentations or more useful than the GAAP information we provide elsewhere in this report.

	Quarter Ended				Six Months Ended				Twelve Months Ended
	2011		2010		2011		2010		2011		2010
Electric revenues	$	119.9	$	106.3	$	247.8	$	219.8	$	510.9	$	444.0
Fuel and purchased power	47.2		44.2		101.4		94.9		205.8		188.6
Electric gross margins	$	72.7	$	62.1	$	146.4	$	124.9	$	305.1	$	255.4

Electric gross margins increased during 2011 in all periods presented mainly due to the Missouri, Kansas, Oklahoma and Arkansas rate increases as well as increased electric sales resulting from favorable weather during the twelve months ended period as compared to the comparable periods in 2010.

Quarter Ended June 30, 2011 Compared to Quarter Ended June 30, 2010

On-System Operating Revenues and Kilowatt-Hour Sales

KWh sales for our on-system customers decreased during the second quarter of 2011 as compared to the second quarter of 2010 primarily due to the loss of approximately 4,200 of our customers who remain unable to return to service due to damaged or destroyed structures resulting from the May 22, 2011 tornado. Revenues for our on-system customers increased approximately $12.3 million, or 12.3%. Rate changes, primarily the September 2010 Missouri rate increase, the July 2010 Kansas rate increase, the September 2010 and March 2011 Oklahoma rate increases and the April 2011 Arkansas rate increase, contributed an estimated $13.4 million to revenues. Negative sales growth (contraction), due to the loss of residences and businesses resulting from the May 22, 2011 tornado, decreased revenues an estimated $2.2 million. Weather and other related factors

38

increased revenues an estimated $1.1 million, primarily due to favorable weather in the second quarter of 2011 and restoration activities that partially mitigated the impact of some of our load loss, as tornado victims and outside volunteers needing housing occupied hotels, rental properties and some temporary structures during much of June. 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 2011 were 1.5% more than the same period last year and 53.5% more than the 30-year average, mainly due to unseasonably hot weather in June 2011.

Despite the loss of thousands of residences during the May 2011 tornado, residential kWh sales increased 0.8% during the second quarter of 2011 mainly due to the warmer weather during the quarter as compared to 2010 and to the positive effect of the restoration activities. Residential revenues increased mainly due to the Missouri, Kansas, Oklahoma and Arkansas rate increases discussed above.

The decrease in commercial kWh sales during the second quarter of 2011 was mainly due to the customer contraction resulting from the loss of businesses, primarily St. John’s hospital, in the May 2011 tornado. Commercial revenues increased mainly due to the Missouri, Kansas, Oklahoma and Arkansas rate increases discussed above.

Industrial kWh sales increased 1.2% during the second quarter of 2011 as compared to the second quarter of 2010. Industrial revenues increased mainly due to the Missouri, Kansas, Oklahoma and Arkansas rate increases discussed above.

On-system wholesale kWh sales increased 3.9% during the second quarter of 2011 as compared to the same period in 2010 reflecting the warmer weather in the second quarter of 2011. Revenues associated with these sales decreased 0.3% as a result of the FERC fuel adjustment clause applicable to such sales and to the portion of FERC revenues that are subject to refund while we are waiting on approval of the Settlement Agreement and Offer of Settlement filed with the FERC on May 24, 2011.

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 our transmission rider in our Arkansas jurisdiction 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 net income.

Although off-system sales decreased during the second quarter of 2011, revenues increased due to our ability to sell on-peak energy at higher prices than compared to the second quarter of 2010 when we sold more off-peak energy. Total purchased power related expenses are included in our discussion of purchased power costs below.

Miscellaneous Revenues

Our miscellaneous revenues were $2.0 million for the second quarter of 2011 as compared to $1.6 million in the second quarter of 2010. These revenues are comprised mainly of transmission revenues, late payment fees and renewable energy credit sales.

Operating Revenue Deductions — Fuel and Purchased Power

During the second quarter of 2011, total electric segment operating expenses increased approximately $9.2 million (9.9%) compared with the same period last year. 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 2011 and 2010.

39

(in millions)	2011			2010
Actual fuel and purchased power expenditures	$	45.6		$	44.8
Missouri fuel adjustment recovery*	2.0			—
Missouri fuel adjustment deferral**	(0.5		)	(0.7		)
Kansas regulatory adjustments**	(0.1		)	—
SWPA amortization***	(0.1		)	—
Unrealized (gain)/loss on derivatives	0.3			0.1
Total fuel and purchased power expense per income statement	$	47.2		$	44.2

*Recovered from customers from prior deferral period.

**A negative amount indicates costs have been under recovered from customers and a positive amount indicates costs have been over recovered from customers. Missouri amount includes the deferral of additional costs due to construction accounting, which terminated as of June 15, 2011, the effective date of rates for our 2010 Missouri rate case.

***Missouri ten year amortization of the $26.6 million payment received from the SWPA in September, 2010.

The overall fuel and purchased power increase reflects increased generation by our coal units as well as increased coal costs.

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 2011 as compared to the second quarter of 2010. This table incorporates all the changes mentioned above.

	Three Months Ended
(in millions)	June 30, 2011 vs. 2010
Coal generation volume	$	3.2
Natural gas generation volume	(4.0		)
Purchased power spot purchase volume	(1.8		)
Coal (cost per mWh)	2.9
Natural gas (cost per mWh)	0.8
Purchased power (cost per mWh)	0.3
Other (primarily fuel adjustments)	1.6
TOTAL	$	3.0

Operating Revenue Deductions — Other Than Fuel and Purchased Power

Regulated operating expenses increased approximately $0.1 million (0.6%) during the second quarter of 2011 as compared to the same period in 2010 primarily due to changes in the following accounts:

(in millions)	2011 vs. 2010
Transmission expense*	$	0.6
Distribution expense	(0.3		)
Steam power other operating expense	0.8
Employee pension expense	0.7
Injuries and damages expense	0.5
Uncollectible accounts expense	0.4
General labor costs	(0.6		)
Professional services	(1.1		)
Other steam power expense**	(1.1		)
Other miscellaneous accounts (netted)	0.2
TOTAL	$	0.1

*  Approximately $0.4 million of this total is for charges incurred for delivering the output from Plum Point to our system.

**Related to Iatan 1 and Iatan 2 construction accounting in accordance with our agreement with the MPSC that allowed deferral of certain costs until the plant additions were included in customer rates.    Construction accounting terminated as of June 15, 2011, the effective date of rates for our 2010 Missouri rate case.

40

Maintenance and repairs expense increased approximately $1.0 million (10.1%) in the second quarter of 2011 as compared to the second quarter of 2010 primarily due to changes in the following accounts:

(in millions)	2011 vs. 2010
Distribution maintenance costs	$	0.7
Maintenance and repairs expense at the Iatan plant	0.7
Maintenance and repairs expense at the SLCC plant	0.3
Maintenance and repairs expense at the Plum Point plant	0.2
Maintenance and repairs expense to Ozark Beach	(0.1		)
Maintenance and repairs expense at the Asbury plant	(0.1		)
Maintenance and repairs expense to the Riverton coal units	(0.7		)
TOTAL	$	1.0

Depreciation and amortization expense increased approximately $3.2 million (25.9%) during the quarter. This reflects additional regulatory amortization expense of $1.9 million granted in our Missouri rate case effective September 10, 2010 and which ended June 15, 2011. The remainder of the increase resulted from increased plant in service in the second quarter of 2011 as compared to the same period in 2010, net of the construction accounting effect of deferred depreciation related to Iatan 2 as allowed in our regulatory agreements. The construction accounting effect of deferring Iatan 2 depreciation expense in the second quarter of 2011 was $0.7 million as compared to $0.3 million of Iatan 1 depreciation expense deferred in the second quarter of 2010. Construction accounting terminated as of June 15, 2011, the effective date of rates for our 2010 Missouri rate case.

Other taxes increased approximately $1.0 million during the second quarter of 2011 due to increased property tax reflecting our additions to plant in service and increased municipal franchise taxes.

Six Months Ended June 30, 2011 Compared to Six Months Ended June 30, 2010

On-System Operating Revenues and Kilowatt-Hour Sales

KWh sales for our on-system customers decreased during the six months ended June 30, 2011 as compared to the six months ended June 30, 2010 primarily due to mild weather in the first quarter of 2011 and the loss of approximately 4,200 of our customers who remain unable to return to service due to damaged or destroyed structures resulting from the May 22, 2011 tornado. Revenues for our on-system customers increased approximately $24.6 million, or 12.0%. Rate changes, primarily the September 2010 Missouri rate increase, the July 2010 Kansas rate increase, the September 2010 and March 2011 Oklahoma rate increases and the April 2011 Arkansas rate increase, contributed an estimated $29.2 million to revenues. Weather and other related factors decreased revenues by an estimated 2.9 million during the six months ended June 30, 2011 compared to the six months ended June 30, 2010. Normal sales growth added $0.5 million to revenues, offset by a sales contraction resulting from the loss of customers due to the tornado, which decreased revenues an estimated $2.2 million during the six months ended June 30, 2011.

The decrease in residential kWh sales during the six months ended June 30, 2011 was primarily due to the loss of residences in the May 2011 tornado and mild weather in the first quarter of 2011 as compared to 2010. Residential revenues increased during the six months ended June 30, 2011 mainly due to the Missouri, Kansas, Oklahoma and Arkansas rate increases discussed above.

Commercial kWh sales decreased during the six months ended June 30, 2011 mainly due to the loss of businesses in the May 2011 tornado and mild weather in the first quarter of 2011. Commercial revenues increased during the six months ended June 30, 2011 mainly due to the Missouri, Kansas, Oklahoma and Arkansas rate increases discussed above.

Industrial kWh sales increased 1.9% during the six months ended June 30, 2011 while the related revenues increased 17.2% mainly due to the Missouri, Kansas, Oklahoma and Arkansas rate increases discussed above.

41

On-system wholesale kWh sales increased 3.5% during the six months ended June 30, 2011. Revenues associated with these sales decreased 7.6% primarily due to the portion of FERC revenues that are subject to refund while we are waiting on approval of the Settlement Agreement and Offer of Settlement filed with the FERC on May 24, 2011.

Off-System Electric Transactions

Off-system revenues were higher during the six months ended June 30, 2011 as compared to the same period in 2010 primarily due to increased demand in the first quarter of 2011. Total purchased power related expenses are included in our discussion of purchased power costs below.

Miscellaneous Revenues

Our miscellaneous revenues were $4.1 million for the six months ended June 30, 2011 as compared to $3.3 million during the same period in 2010. These revenues are comprised mainly of transmission revenues, late payment fees and renewable energy credit sales.

Operating Revenue Deductions — Fuel and Purchased Power

During the six months ended June 30, 2011, total fuel and purchased power expenses increased approximately $6.5 million (6.9%). 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 six months ended June 30, 2011 and 2010.

(in millions)	2011			2010
Actual fuel and purchased power expenditures	$	95.9		$	98.0
Missouri fuel adjustment recovery*	5.0			(0.5		)
Missouri fuel adjustment deferral**	0.5			(2.6		)
Kansas regulatory adjustments**	(0.1		)	(0.4		)
SWPA amortization***	(0.1		)	—
Unrealized loss on derivatives	0.2			0.4
Total fuel and purchased power expense per income statement	$	101.4		$	94.9

*Recovered from customers from prior deferral period.

**A negative amount indicates costs have been under recovered from customers and a positive amount indicates costs have been over recovered from customers. Missouri amount includes the deferral of additional costs due to construction accounting, which terminated as of June 15, 2011, the effective date of rates for our 2010 Missouri rate case.

***Missouri ten year amortization of the $26.6 million payment, received from the SWPA in September, 2010.

The overall fuel and purchased power increase reflects increased generation by our coal units, offset by decreased generation by our gas turbines and decreased purchased power, as well as increased expense from our fuel adjustments.

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, 2011 as compared to the six months ended June 30, 2010. This table incorporates all the changes mentioned above. As shown below, the largest negative impacts on fuel and purchased power costs were increased generation by our coal units and increased expense from our fuel adjustments, primarily due to increases in fuel expense as we collect costs previously deferred.

42

	Six Months Ended
(in millions)	June 30, 2011 vs. 2010
Coal generation volume	$	7.6
Natural gas generation volume	(6.8		)
Purchased power spot purchase volume	(4.9		)
Coal (cost per mWh)	4.0
Natural gas (cost per mWh)	(1.5		)
Purchased power (cost per mWh)	0.6
Other (primarily fuel adjustments)	7.5
TOTAL	$	6.5

Operating Revenue Deductions — Other Than Fuel and Purchased Power

Regulated operating expenses increased approximately $1.5 million (4.6%) during the six months ended June 30, 2011 as compared to the same period in 2010 primarily due to changes in the following accounts:

(in millions)	2011 vs. 2010
Transmission expense*	$	1.4
Distribution expense	(0.1		)
Steam power other operating expense	1.6
Injuries and damages expense	0.5
General labor costs	(0.5		)
Employee pension expense	1.3
Professional services	(1.1		)
Uncollectible accounts	0.2
Other steam power expense**	(2.1		)
Other miscellaneous accounts (netted)	0.3
TOTAL	$	1.5

*  Approximately $0.9 million of this total is for charges incurred for delivering the output from Plum Point to our system.

**Related to Iatan 1 and Iatan 2 construction accounting in accordance with our agreement with the MPSC that allowed deferral of certain costs until the plant additions were included in customer rates. Construction accounting terminated as of June 15, 2011, the effective date of rates for our 2010 Missouri rate case.

Maintenance and repairs expense increased approximately $2.4 million (14.1%) during the six months ended June 30, 2011 as compared to the six months ended June 30, 2010 primarily due to changes in the following accounts:

(in millions)	2011 vs. 2010
Distribution maintenance costs	$	1.4
Maintenance and repairs expense at the Iatan plant	1.1
Maintenance and repairs expense at the SLCC plant	0.7
Maintenance and repairs expense at the Plum Point plant	0.5
Maintenance and repairs expense at the Asbury plant	(0.2		)
Maintenance and repairs expense to the Riverton coal units	(1.1		)
TOTAL	$	2.4

Depreciation and amortization expense increased approximately $6.9 million (28.1%) during the six months ended June 30, 2011. This reflects additional regulatory amortization expense of $4.4 million granted in our Missouri rate case effective September 10, 2010 and which ended June 15, 2011. The remainder of the increase resulted from increased plant in service during the six months ended June 30, 2011 as compared to the same period in 2010, net of the construction accounting effect of deferred depreciation related to Iatan 2 as allowed in our regulatory agreements. The construction accounting effect of deferring Iatan 2 depreciation expense was $1.5 million as

43

compared to $0.7 million of Iatan 1 depreciation expense in the prior period. Construction accounting terminated as of June 15, 2011, the effective date of rates for our 2010 Missouri rate case.

Other taxes increased approximately $2.0 million during the six months ended June 30, 2011 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, 2011, kWh sales to our on-system customers increased 2.5% with the associated revenues increasing approximately $59.0 million (14.1%). Rate changes, primarily the September 2010 Missouri rate increase, the July 2010 Kansas rate increase, the September 2010 and March 2011 Oklahoma rate increases and the April 2011 Arkansas rate increase, contributed an estimated $46.2 million to revenues. Weather and other related factors increased revenues an estimated $13.1 million. Normal sales growth added $1.9 million to revenues, offset by sales contraction resulting from the loss of customers due to the tornado, which decreased revenues an estimated $2.2 million during the twelve months ended June 30, 2011. The increase in residential and commercial kWh sales during the twelve months ended June 30, 2011 was primarily due to favorable weather, while the increase in revenues reflects the positive weather as well as the Missouri, Kansas, Oklahoma and Arkansas rate increases. Industrial kWh sales increased during the twelve months ended June 30, 2011 as compared to the same period in 2010 when there was a slowdown created by economic uncertainty. Industrial revenues also increased due to the Missouri, Kansas, Oklahoma and Arkansas rate increases. On-system wholesale kWh sales increased during the twelve months ended June 30, 2011 reflecting increased market demand resulting from the favorable weather.

Off-System Electric Transactions

Off-system revenues increased during the twelve months ended June 30, 2011 as compared to the same period in 2010 primarily due to increased market demand. Total purchased power related expenses are included in our discussion of purchased power costs below.

Miscellaneous Revenues

Our miscellaneous revenues were $8.3 million for the twelve months ended June 30, 2011 as compared to $6.9 million in the same period of 2010. These revenues are comprised mainly of transmission revenues, late payment fees and renewable energy credit sales.

Operating Revenue Deductions — Fuel and Purchased Power

During the twelve months ended June 30, 2011, total fuel and purchased power expenses increased approximately $17.2 million (9.1%). 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, 2011 and 2010.

(in millions)	2011			2010
Actual fuel and purchased power expenditures	$	197.9		$	191.7
Missouri fuel adjustment recovery*	8.6			1.0
Missouri fuel adjustment deferral**	(1.4		)	(4.0		)
Kansas regulatory adjustments**	0.2			(0.2		)
SWPA amortization***	(0.1		)	—
Unrealized loss on derivatives	0.6			0.1
Total fuel and purchased power expense per income statement	$	205.8		$	188.6

*Recovered from customers from prior deferral period.

44

**A negative amount indicates costs have been under recovered from customers and a positive amount indicates costs have been over recovered from customers. Missouri amount includes the deferral of additional costs due to construction accounting, which terminated as of June 15, 2011, the effective date of rates for our 2010 Missouri rate case.

***Missouri ten year amortization of the $26.6 million payment received from the SWPA in September, 2010.

The overall fuel and purchased power increase includes increased generation by both our coal units and combustion turbines as well as increased expense from our fuel adjustments.

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, 2011 as compared to the twelve months ended June 30, 2010. This table incorporates all the changes mentioned above. As shown below, the increase in fuel and purchased power costs is mainly due to increased generation by both our coal units and combustion turbines and increased expense from our fuel adjustments as we collect fuel costs previously deferred.

	Twelve Months Ended
(in millions)	June 30, 2011 vs. 2010
Coal generation volume	$	12.8
Natural gas generation volume	8.6
Purchased power spot purchase volume	(11.4		)
Coal (cost per mWh)	3.6
Natural gas (cost per mWh)	(7.4		)
Purchased power (cost per mWh)	1.5
Other (primarily fuel adjustments)	9.5
TOTAL	$	17.2

Operating Revenue Deductions — Other Than Fuel and Purchased Power

Regulated operating expenses increased approximately $5.5 million (8.3%) during the twelve months ended June 30, 2011 as compared to the same period in 2010 primarily due to changes in the following accounts:

(in millions)	2011 vs. 2010
Transmission expense*	$	2.7
Employee pension expense	2.1
Injuries and damages expense	0.7
General labor costs	0.3
Employee health care expense	0.5
Customer accounts expense	0.3
Steam power other operating expense	2.2
Other steam power expense**	(3.3		)
TOTAL	$	5.5

*  Approximately $1.6 million of this total is for charges incurred for delivering the output from Plum Point to our system.

**Related to Iatan 1 and Iatan 2 construction accounting in accordance with our agreement with the MPSC that allowed deferral of certain costs until the plant additions were included in customer rates. Construction accounting terminated as of June 15, 2011, the effective date of rates for our 2010 Missouri rate case.

Maintenance and repairs expense increased approximately $5.4 million (16.4%) during the twelve months ended June 30, 2011 as compared to the twelve months ended June 30, 2010 primarily due to changes in the following accounts:

45

(in millions)	2011 vs. 2010
Distribution maintenance costs	$	2.3
Transmission maintenance costs	0.4
Maintenance and repairs expense at the Iatan plant	1.6
Maintenance and repairs expense at the SLCC plant	1.2
Maintenance and repairs expense at the Plum Point plant	0.9
Maintenance and repairs expense to the Riverton combustion turbines	0.4
Maintenance and repairs expense at the Asbury plant	(0.3		)
Maintenance and repairs expense to the Riverton coal units	(1.1		)
TOTAL	$	5.4

Depreciation and amortization expense increased approximately $11.9 million (24.3%) during the twelve months ended June 30, 2011. This reflects additional regulatory amortization expense of $7.5 million granted in our Missouri rate case effective September 10, 2010 and which ended June 15, 2011. The remainder of the increase resulted from increased plant in service during the twelve months ended June 30, 2011 as compared to the same period in 2010, net of the construction accounting effect of deferred depreciation related to Iatan 2 as allowed in our regulatory agreements. The construction accounting effect of deferring Iatan 2 depreciation expense was $2.6 million as compared to $1.3 million of Iatan 1 depreciation expense in the prior period. Construction accounting terminated as of June 15, 2011, the effective date of rates for our 2010 Missouri rate case.

Other taxes increased approximately $3.4 million during the six months ended June 30, 2011 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)	2011	2010	change		2011	2010	Change		2011	2010	change
Residential	0.29	0.19	47.1	%	1.69	1.71	(1.4	)%	2.66	2.79	(5.0	)%
Commercial	0.18	0.12	46.3		0.80	0.77	3.8		1.29	1.33	(2.6	)
Industrial	0.02	0.02	37.3		0.07	0.06	11.5		0.11	0.11	5.6
Other*	0.00	0.00	116.6		0.02	0.02	0.9		0.04	0.04	(2.7	)
Total retail sales	0.49	0.33	46.6		2.58	2.56	0.5		4.10	4.27	(4.0	)
Transportation sales	1.07	1.09	(1.1	)	2.55	2.69	(4.9	)	4.69	4.93	(4.9	)
Total gas operating sales	1.56	1.42	10.0		5.13	5.25	(2.3	)	8.79	9.20	(4.5	)

46

Operating Revenues and Cost of Gas Sold

	Three Months Ended						Six months ended						Twelve months ended
($ in millions)	2011		2010		% change		2011		2010		% change		2011		2010		% change
Residential	$	4.3	$	3.9	12.0	%	$	17.9	$	20.1	(11.3	)%	$	30.0	$	33.3	(10.1	)%
Commercial	1.9		1.6		20.4		7.6		8.1		(6.0	)	12.8		14.2		(9.3	)
Industrial	0.1		0.1		25.5		0.5		0.5		(3.9	)	0.8		0.9		(13.0	)
Other*	0.1		0.0		68.7		0.2		0.3		(5.7	)	0.4		0.4		(8.8	)
Total retail revenues	$	6.4	$	5.6	14.9		$	26.2	$	29.0	(9.7	)	$	44.0	$	48.8	(9.9	)
Other revenues	0.2		0.1		(7.5	)	0.2		0.2		12.3		0.4		0.3		55.9
Transportation revenues*	0.7		0.8		(4.2	)	1.9		1.9		(0.6	)	3.7		3.3		11.7
Total gas operating revenues	$	7.3	$	6.5	12.1		$	28.3	$	31.1	(9.0	)	$	48.1	$	52.4	(8.2	)
Cost of gas sold	2.7		2.3		19.7		14.8		17.4		(15.1	)	24.0		29.5		(18.6	)
Gas operating revenues over cost of gas in rates	$	4.6	$	4.2	8.0		$	13.5	$	13.7	(1.2	)	$	24.1	$	22.9	5.2

*Other includes other public authorities and interdepartmental usage.

Quarter Ended June 30, 2011 Compared to Quarter Ended June 30, 2010

Operating Revenues and bcf Sales

Gas retail sales increased 46.6% during the second quarter of 2011 as compared to 2010 primarily due to favorable weather and customer growth of approximately 0.1%. Although gas sales are normally less during the summer months, as the heating season runs from November to March of each year, the cooler weather in April and May of 2011 and the increase in customer growth led to an increase in sales for the second quarter of 2011. Residential and commercial sales increased during the second quarter of 2011 as compared to the second quarter of 2010 primarily due to the favorable weather and customer growth. Heating degree days were 52.8% higher in the second quarter of 2011 as compared to the second quarter of 2010 and 0.6% lower than the 30-year average mainly due to cooler weather in April and May of 2011. Industrial sales increased 37.3% during the second quarter of 2011 as compared to the same period in 2010.

During the second quarter of 2011, gas segment revenues were approximately $7.3 million as compared to $6.5 million in the second quarter of 2010. Our PGA revenue (which represents the cost of gas recovered from our customers) was approximately $2.7 million as compared to $2.3 million in the second quarter of 2010, an increase of approximately $0.4 million. This increase was largely driven by the increase in sales. Our margin (defined as gas operating revenues less cost of gas in rates) for the second quarter of 2011 increased $0.3 million as compared to the second quarter of 2010 due to the increase in sales.

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, 2011, we had over recovered purchased gas costs of $1.4 million recorded as a regulatory liability.

Operating Revenue Deductions

Total other operating expenses were approximately $2.0 million during the second quarter of 2011 as compared to $2.3 million in the second quarter of 2010, mainly due to a $0.1 million decrease in general labor expense, a $0.1 million decrease in uncollectible accounts expense and a $0.1 million decrease in other miscellaneous expense.

Our gas segment had a $27,000 net loss for the second quarter of 2011 as compared to a net loss of $0.4 million for the second quarter of 2010.

47

Six Months Ended June 30, 2011 Compared to Six Months Ended June 30, 2010

Operating Revenues and bcf Sales

Gas retail sales increased 0.5% during the six months ended June 30, 2011 as compared to the same period in 2010, mainly due to favorable weather in the first and second quarters of 2011 as compared to the same period in 2010. Residential sales decreased 1.4% during the six months ended June 30, 2011 as compared to the same period in 2010 and commercial sales increased 3.8% during the same period. Industrial sales increased during the six months ended June 30, 2011 as compared to the same period in 2010.

During the six months ended June 30, 2011, gas segment revenues were approximately $28.3 million as compared to $31.1 million in the six months ended June 30, 2010, a decrease of $2.8 million. This decrease was largely driven by a lower PGA that went into effect November 2, 2010. During the six months ended June 30, 2011, our PGA revenue was approximately $14.8 million as compared to $17.4 million during the six months ended June 30, 2010, a decrease of approximately $2.6 million. Our margin for the six months ended June 30, 2011 decreased $0.2 million as compared to the same period in 2010 mainly due to the decrease in transportation sales.

Operating Revenue Deductions

Total other operating expenses were $4.1 million for the six months ended June 30, 2011 as compared to $5.0 million for the six months ended June 30, 2010. This decrease was mainly due to a $0.3 million decrease in uncollectible accounts expense, a $0.2 million decrease in employee pension expense, a $0.1 million decrease in general labor expense, a $0.1 million decrease in rents expense and a $0.2 million decrease in other miscellaneous expense.

Our gas segment had net income of $2.2 million for the six months ended June 30, 2011 as compared to $1.9 million for the six months ended June 30, 2010.

Twelve Months Ended June 30, 2011 Compared to Twelve Months Ended June 30, 2010

Operating Revenues and bcf Sales

Gas retail sales decreased 4.0% during the twelve months ended June 30, 2011 reflecting customer contraction during the third and fourth quarters of 2010 and the first quarter of 2011. Residential and commercial sales decreased during the twelve months ended June 30, 2011 reflecting the customer contraction. Industrial sales increased.

During the twelve months ended June 30, 2011, gas segment revenues were approximately $48.1 million as compared to $52.4 million in the twelve months ended June 30, 2010, a decrease of $4.3 million. This decrease was largely driven by a decrease in the PGA rate that went into effect November 2, 2010. During the twelve months ended June 30, 2011, our PGA revenue was approximately $24.0 million as compared to $29.5 million during the twelve months ended June 30, 2010, a decrease of approximately $5.5 million. Our margin for the twelve months ended June 30, 2011 increased $1.2 million as compared to the same period in 2010.

Operating Revenue Deductions

Total other operating expenses were $8.6 million for the twelve months ended June 30, 2011 as compared to $9.8 million for the twelve months ended June 30, 2010. This decrease was mainly due to a $0.7 million decrease in employee pension expense, a $0.4 million decrease in uncollectible accounts expense and a $0.1 million decrease in other miscellaneous expense.

Our gas segment had net income of $2.9 million for the twelve months ended June 30, 2011 as compared to $1.8 million for the twelve months ended June 30, 2010.

48

Consolidated Company

Income Taxes

The following table shows the changes in our provision for income taxes (in millions) and our consolidated effective federal and state income tax rates for the applicable periods ended June 30, 2011:

	Three Months Ended						Six Months Ended						Twelve Months Ended
	2011			2010			2011			2010			2011			2010
Consolidated provision for income taxes	$	5.6		$	4.5		$	12.8		$	14.4		$	28.9		$	24.6
Consolidated effective federal and state income tax rates	37.8		%	37.7		%	37.8		%	47.5		%	35.5		%	38.9		%

See Note 12 for more information and discussion concerning our income tax provision and effective tax rates.

Nonoperating Items

The following table shows the total allowance for funds used during construction (AFUDC) for the applicable periods ended June 30. AFUDC decreased during all three periods in 2011 as compared to the same periods in 2010 reflecting the completion of Iatan 2 and the Plum Point Energy Station in 2010.

	Three Months Ended				Six Months Ended				Twelve Months Ended
($ in millions)	2011		2010		2011		2010		2011		2010
Allowance for equity funds used during construction	$	0.1	$	1.9	$	0.1	$	3.7	$	0.9	$	7.2
Allowance for borrowed funds used during construction	0.0		2.4		0.1		4.8		0.9		8.5
Total AFUDC	$	0.1	$	4.3	$	0.2	$	8.5	$	1.8	$	15.7

Total interest charges on long-term and short-term debt for the periods ended June 30, 2011 are shown below. The decreases in long-term debt interest for all periods presented reflect the redemption of $48.3 million aggregate principal amount of our Senior Notes, 7.05% Series due 2022, which were redeemed on August 27, 2010, and replaced by $50 million principal amount 5.20% first mortgage bonds issued August 25, 2010. The decrease also reflects the redemption of 6.5% first mortgage bonds on April 1, 2010 and the redemption of our 8.5% trust preferred securities on June 28, 2010, which were replaced by 4.65% first mortgage bonds issued May 28, 2010. The decreases in short-term debt interest for each period 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		%
	2011		2010		Change*		2011		2010		Change*		2011		2010		Change*
Long-term debt interest	10.6		10.1		5.5	%	21.3		20.6		3.4	%	42.7		42.1		1.3	%
Short-term debt interest	—		0.2		(93.6	)	0.0		0.5		(90.5	)	0.2		0.8		(77.3	)
Trust preferred securities interest	—		1.0		(100.0	)	—		2.1		(100.0	)	—		4.2		(100.0	)
Iatan1and 2 carrying charges	(1.0	)	(0.6	)	66.5		(2.2	)	(1.2	)	82.0		(4.2	)	(1.9	)	117.3
Other interest	0.3		0.3		11.6		0.5		0.4		3.9		0.9		0.8		7.2
Total interest charges	9.9		11.0		(9.7	)	19.6		22.4		(12.4	)	39.6		46.0		(14.1	)

*Beginning in the second quarter of 2009, we deferred Iatan 1 carrying charges to reflect construction accounting 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. We began deferring Iatan 2 carrying charges in the third quarter of 2010. Deferral ends when the plant is placed in rates. Iatan 1 was placed in rates in September 2010. Iatan 2 was placed in rates June 15, 2011. See Note 3 and Rate Matters below for additional information regarding carrying charges.

49

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 depreciation and 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, amortization and retirement of utility plant or 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.

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

Jurisdiction	Date Requested	Annual Increase Granted		Percent Increase Granted		Date Effective
Missouri – Electric	September 28, 2010	$	18,700,000	4.70	%	June 15, 2011
Missouri – Electric	October 29, 2009	$	46,800,000	13.40	%	September 10, 2010
Missouri – Electric	October 1, 2007	$	22,040,395	6.70	%	August 23, 2008
Kansas – Electric	November 4, 2009	$	2,800,000	12.4	%	July 1, 2010
Oklahoma – Electric	January 28, 2011	$	1,063,100	9.32	%	March 1, 2011
Oklahoma – Electric	March 25, 2010	$	1,456,979	15.70	%	September 1, 2010
Arkansas – Electric	August 19, 2010	$	2,104,321	19.00	%	April 13, 2011
Missouri – Gas	June 5, 2009	$	2,600,000	4.37	%	April 1, 2010

Electric Segment

Missouri

2010 Rate Case

On September 28, 2010, we filed a rate increase request with the MPSC for an annual increase in base rates for our Missouri electric customers in the amount of $36.5 million, or 9.2% to recover the Iatan 2 costs and other cost of service items not included in our 2009 Missouri rate case, effective September 10, 2010. A settlement agreement among the parties to the case was reached and filed with the MPSC on May 27, 2011 reflecting an overall annual increase in rates of $18.7 million, or approximately 4.7% to become effective on June 15, 2011. As part of the settlement, regulatory amortization expense of $14.5 million annually and construction accounting terminated as of June 15, 2011. The MPSC approved the settlement agreement on June 1, 2011 and the new rates became effective on June 15, 2011.

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 this 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.

50

A stipulated agreement was filed on May 12, 2010, calling for an annual increase of $46.8 million, provided the Plum Point Generating Station met its in-service criteria by August 15, 2010. If the in-service criteria were not met by such date, a base rate increase of $33.1 million was stipulated. The Plum Point Generating Station completed its in-service criteria testing on August 12, 2010, with an in-service date of August 13, 2010, thus new rates, providing for the full increase of $46.8 million, were effective September 10, 2010. The $46.8 million authorized increase in annual revenues includes $36.8 million in base rate revenue and $10 million in regulatory amortization. The regulatory amortization, which is treated as additional book depreciation for rate-making purposes and is reflected in the financial statements, was granted to provide additional cash flow through rates. This regulatory amortization is related to our investments in facilities and environmental upgrades completed during the recent construction cycle. As agreed in our regulatory plan, we used construction accounting for our Iatan 2 project. As noted above, regulatory amortization expense of $14.5 million annually and construction accounting terminated as of June 15, 2011 as a result of our 2010 rate case. (See Note 3 and Note 7 of “Notes to Consolidated Financial Statements”). We 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. 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.

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 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.

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 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 filed appeals with the Western District Court of Appeals. Explorer Pipeline was dismissed from the pending appeal on October 18, 2010.

51

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 of the rates from the next Kansas case, which was filed on June 17, 2011. This case requests a rate increase of $1.5 million, or 6.39%. The rate increase is being requested to recover the remaining costs associated with our investment in the Iatan 1, Iatan 2 and Plum Point generating units and the depreciation and operation and maintenance costs deferred since the in-service dates of the units. The June 17, 2011 filing was made under the KCC’s abbreviated rate case rules, which the KCC authorized in our 2009 Kansas rate case. The case includes a request to recover the Iatan and Plum Point cost deferrals over a 3 year period.

Oklahoma

On March 25, 2010, we requested a capital cost recovery rider (CCRR) at the Oklahoma Corporation Commission (OCC). The rider was 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 have increased our operating revenue by approximately $3 million, or approximately 33%, in Oklahoma in a series of three steps to be followed with a general rate case in 2011. On August 30, 2010, we were granted a two-phase Capital Reliability Rider (CRR) by the OCC. The first phase of the rider was put into place for Oklahoma customers for usage on and after September 1, 2010, and results in an overall annual base revenue increase of approximately $1.5 million, or 15.7%. In total, the CRR revenue has been specifically limited by the OCC to an overall annual revenue increase of $2.6 million, or 27.67% increase. On January 28, 2011 we requested the approval by the OCC of the phase 2 rates of the CRR. We requested an additional $1.1 million, which brings the total annual revenue under the OCC to approximately $2.5 million effective March 25, 2011. The CRR revenue being collected is subject to refund/true-up in the next general rate case. On June 30, 2011, we filed a request with the OCC for an annual increase in base rates for our Oklahoma electric customers (which would replace the CRR with permanent rates) in the amount of $0.6 million, or 4.1% over the base rate and CRR revenues that are currently in effect.

Arkansas

On August 19, 2010, we filed a rate increase request with the Arkansas Public Service Commission (APSC) for an annual increase in base rates for our Arkansas electric customers in the amount of $3.2 million, or 27.3%. On February 2, 2011 we entered into a unanimous settlement agreement with the parties involved. The settlement includes a general rate increase of $2.1 million, or 19%. The APSC approved the settlement on April 12, 2011 with the new rates effective April 13, 2011.

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. As of June 30, 2011, we had collected $1.2 million in rates subject to refund. 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

52

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 September 15, 2010, the parties agreed to a settlement in principle and on May 24, 2011, we, the Missouri Public Utility Alliance and the cities of Monett, Mt. Vernon and Lockwood, Missouri filed a Settlement Agreement and Offer of Settlement with the FERC. We expect to refund approximately $1.2 million as a result of this settlement.

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

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 for a public utility’s waiver. 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. Our July 13, 2009 filing stated that continuation of our waiver, issued in 1997 and reaffirmed in 2004, was appropriate and reasonable. 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. On April 21, 2011, the FERC issued its order and denied our request for a continuation of our waiver and ordered our compliance to Order 717 Standard of Conduct requirements effective June 21, 2011. Since we voluntarily implemented Order 717 Standard of Conduct policies and procedures on July 19, 2009, we did not have any issues in fully complying with the April 21, 2011 order.

See Note 3 in our Annual Report on Form 10-K for the year ended December 31, 2010 for additional information on Competition.

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 the majority of the funds required in 2011 for our budgeted capital expenditures (as discussed in “Capital Requirements and Investing Activities” below). 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

53

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, impacts of the 2011 tornado and other factors. See Item 1A, “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2010 for additional information on items that could impact our liquidity and capital resource requirements. The following table provides a summary of our operating, investing and financing activities for the quarters ended June 30:

Summary of Cash Flows

	Six Months Ended June 30,
(in millions)	2011			2010			Change
Cash provided by/(used in):
Operating activities	$	63.4		$	42.0		$	21.4
Investing activities	(41.4		)	(59.2		)	17.8
Financing activities	(28.5		)	18.3			(46.8		)
Net change in cash and cash equivalents	$	(6.5	)	$	1.1		$	(7.6	)

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, 2011 Compared to 2010.  During the six months ended June 30, 2011, our net cash flows provided from operating activities increased $21.4 million or 51.1% from 2010. This change resulted from the following:

·Changes in net income - $5.1 million.

·Changes in depreciation and amortization, reflecting increased regulatory amortization, plant in service and fuel deferral amortization - $13.5 million

·Changes in pension and other post retirement benefit costs primarily due to the result of $15.6 million in pension contributions during the six months ended June 30, 2011 — $(14.9) million.

·Increased deferrals for income taxes, reflecting positive impacts for accelerated tax depreciation and adjustments to deferred taxes related to pension and OPEB benefits- $10.1 million.

·Changes in receivables due to higher insurance receipts in 2010 for a generator failure and seasonal levels of trade accounts receivable offset by lower unbilled revenues and income tax refunds collected- $6.2 million.

·Changes in accounts payable mostly due to storm related activities - $7.1 million.

·Changes in prepaid expenses and deferred charges mostly reflecting certain regulatory treatment of fuel charges and carrying costs - $(7.7) million.

·Lower equity AFUDC - $3.6 million

·Changes in accrued property and local taxes - $(2.3) million.

Capital Requirements and Investing Activities

Our net cash flows used in investing activities decreased $17.8 million during the six months ended June 30, 2011 as compared to the same period in 2010.

54

Our capital expenditures incurred totaled approximately $52.4 million during the six months ended June 30, 2011 compared to $56.6 million for the six months ended June 30, 2010. The decrease was primarily the result of a decrease in new generation construction partially offset by increased storm expense due to the May 2011 tornado.

A breakdown of the capital expenditures for the six months ended June 30, 2011 and 2010 is as follows:

	Capital Expenditures
(in millions)	2011			2010
Distribution and transmission system additions	$	20.3		$	16.0
Storms	15.6			—
New Generation — Plum Point Energy Station	—			5.3
New Generation — Iatan 2	3.3			30.6
Additions and replacements — electric plant	4.5			2.9
Gas segment additions and replacements	0.9			0.8
Transportation	0.9			0.8
Other (including retirements and salvage -net) (1)	5.5			(1.8		)
Subtotal	51.0			54.6
Non-regulated capital expenditures (primarily fiber optics)	1.4			2.0
Subtotal capital expenditures incurred (2)	52.4			56.6
Adjusted for capital expenditures payable (3)	(11.0		)	2.6
Total cash outlay	$	41.4		$	59.2

(1) Other includes equity AFUDC of $(0.1) million and $(3.7) million for 2011 and 2010, 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.

Approximately 66% of our cash requirements for capital expenditures during the second quarter of 2011 were satisfied internally from operations (funds provided by operating activities less dividends paid). The remaining amounts of such requirements were satisfied from short-term borrowings and proceeds from our sales of common stock discussed below.

We estimate that internally generated funds will provide all of the funds required for the remainder of our budgeted 2011 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, if 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 $46.9 million to ($28.5) million during the second quarter of 2011 as compared to $18.3 million in the second quarter of 2010, primarily due to a decrease in proceeds (net of repayments of long-term debt) received from new issuances of long term debt and equity in 2011 as compared to 2010.

On January 28, 2011, we filed a $400 million shelf registration statement with the SEC covering our common stock, unsecured debt securities, preference stock, and first mortgage bonds. This shelf registration statement became effective on February 7, 2011. We plan to use proceeds under this shelf to fund capital expenditures, refinancings of existing debt or general corporate needs during the effective period. The issuance of securities under this shelf is subject to the receipt of local regulatory approvals. We have received regulatory approval from Kansas and Oklahoma but are awaiting approvals from the remaining states in our electric service territory.

On January 26, 2010, we entered into the Second Amended and Restated Unsecured Credit Agreement which amended and restated our $150 million revolving credit facility. This agreement extended the termination date of the revolving credit facility from July 15, 2010 to January 26, 2013.

55

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, 2011, we are in compliance with these ratios. Our total indebtedness is 52.0% of our total capitalization as of June 30, 2011 and our EBITDA is 5.2 times our interest charges. 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, 2011. However, $18.5 million was used to back up our outstanding commercial paper.

The principal amount of all series of first mortgage bonds outstanding at any one time under the EDE Mortgage is limited by terms of the mortgage to $1 billion. Substantially all of the property, plant and equipment of The Empire District Electric Company (but not its subsidiaries) is subject to the lien of the EDE Mortgage. Restrictions in the EDE mortgage bond indenture could affect our liquidity. The EDE Mortgage contains a requirement that for new first mortgage bonds to be issued, our net earnings (as defined in the EDE Mortgage) for any twelve consecutive months within the fifteen months preceding issuance must be two times the annual interest requirements (as defined in the EDE Mortgage) on all first mortgage bonds then outstanding and on the prospective issue of new first mortgage bonds. Our earnings for the twelve months ended June 30, 2011 would permit us to issue approximately $435.2 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, 2011, we had retired bonds and net property additions which would enable the issuance of at least $640.5 million principal amount of bonds if the annual interest requirements are met. As of June 30, 2011, 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, 2011, this test would allow us to issue approximately $8.5 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	F3	P-2	A-3
Outlook	Stable	Stable	Positive

*Not rated

On March 10, 2011, Standard & Poor’s revised its outlook on us from stable to positive and affirmed the corporate credit rating at BBB-, citing greater-than-expected improvement in our financial condition from the winding down of our heavy construction program, sale of $120 million of common stock in 2010, rate increases and enhanced cost recovery via new rate riders. On May 14, 2010, Moody’s upgraded our First Mortgage Bonds from Baa1 to A3 and upgraded its outlook from negative to stable. On April 14, 2011, Moody’s reaffirmed all of our other ratings. On April 1, 2010, Fitch revised their rating outlook on us to stable. On March 24, 2011, Fitch revised our commercial paper

56

rating from F2 to F3 and reaffirmed our other ratings. The rating action was not based on a specific action or event on our part, but reflected their traditional linkage of long-term and short-term Issuer Default Ratings.

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.

CONTRACTUAL OBLIGATIONS

Our contractual obligations have not significantly changed at June 30, 2011, compared to December 31, 2010 with the exception of our estimate for pension and post retirement benefits funding. Our estimate for 2011 pension benefit funding has lowered by $1.5 million, from $21.4 million to $19.9 million, and post retirement benefit obligation funding estimates have been reduced by $2.2 million, from $5.7 million to $3.5 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). In response to the expected loss of revenues resulting from the May 22, 2011 tornado, our current level of retained earnings and other relevant factors, our Board of Directors suspended our quarterly dividend for the third and fourth quarters of 2011. Based on current conditions and knowledge, our Board of Directors expects the dividend will be re-established at an approximate level of $0.25 per quarter after this two quarter suspension.

Our diluted earnings per share were $0.51 for the six months ended June 30, 2011 and were $1.17 and $1.18 for the years ended December 31, 2010 and 2009, respectively. Dividends paid per share were $0.64 for the six months ended June 30, 2011 and $1.28 for each of the years ended December 31, 2010 and 2009.

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, 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. On June 9,

57

2011, we amended the EDE Mortgage in order to provide us with additional flexibility to pay dividends to our shareholders by permitting the payment of any dividend or distribution on, or purchase of, shares of its common stock within 60 days after the related date of declaration or notice of such dividend, distribution or purchase if (i) on the date of declaration or notice, such dividend, distribution or purchase would have complied with the provisions of the EDE Mortgage and (ii) as of the last day of the calendar month ended immediately preceding the date of such payment, our ratio of total indebtedness to total capitalization (after giving pro forma effect to the payment of such dividend, distribution, or purchase) was not more than 0.625 to 1.

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 on Form 10-K for the year ended December 31, 2010 for a discussion of additional critical accounting policies. There were no changes in these policies in the quarter ended June 30, 2011.

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 62.3% of our 2010 generation fuel supply need through coal. Approximately 92% of our 2010 coal supply was Western coal. We have contracts and binding proposals to supply a portion of the fuel for our coal plants through 2014. These contracts satisfy approximately 100% of

58

our anticipated fuel requirements for 2011, 65% for 2012, 61% for 2013 and 31% for our 2014 requirements for our Asbury and Riverton coal plants. In order to manage our exposure to fuel prices, future coal supplies will be acquired using a combination of short-term and long-term contracts.

We are exposed to changes in market prices for natural gas we must purchase to run our combustion turbine generators. Our natural gas procurement program is designed to 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 22, 2011, 80%, or 2.1 million Dths’s, of our anticipated volume of natural gas usage for our electric operations for the remainder of 2011 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, 2011, our natural gas cost would increase by approximately $0.8 million based on our June 30, 2011 total hedged positions for the next twelve months. However, this is probable of recovery through fuel adjustment mechanisms 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, 2011, we have 0.7 million Dths in storage on the three pipelines that serve our customers. This represents 36.6% of our storage capacity.

The following table sets forth our long-term hedge strategy of mitigating price volatility for our customers by hedging a minimum of expected gas usage for the current winter season and the next two winter seasons by the beginning of the Actual Cost Adjustment (ACA) year at September 1 and illustrates our hedged position as of June 30, 2011 (in thousands). 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.

Season	Minimum % Hedged	Dth Hedged Financial	Dth Hedged Physical	Dth in Storage	Actual % Hedged
Current	50%	460,000	301,714	735,606	45	%
Second	Up to 50%	310,000	—	—	9	%
Third	Up to 20%	—	—	—	—	%
Total		770,000	301,714	735,606

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, 2011 and December 31, 2010. There were no margin deposit liabilities at these dates.

(in millions)	June 30, 2011		December 31, 2010
Margin deposit assets	$	4.0	$	3.9

59

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, 2011, 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	$	12.3
Net unrealized mark-to-market losses for financial natural gas contracts	4.4
Net credit exposure	$	16.7

The $4.4 million net unrealized mark-to-market loss for financial natural gas contracts is comprised of $4.5 million that our counterparties are exposed to Empire for unrealized losses and $0.04 million of exposure to Empire of unrealized gains from 1 counterparty. 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, 2011, we have $4.0 million on deposit for NYMEX contract exposure to Empire, of which $3.8 million represents our collateral requirement. In addition, if NYMEX gas prices decreased 25% from their June 30, 2011 levels, we would be required to post an additional $2.5 million in collateral. If these prices increased 25%, our collateral requirement would decrease $2.7 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 2011 than in 2010, our interest expense would increase, and income before taxes would decrease by less than $0.5 million. This amount has been determined by considering the impact of the hypothetical interest rates on our highest month-end commercial paper balance for 2010. 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, 2011.

There have been no changes in our internal control over financial reporting that occurred during the second quarter of 2011 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

60

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. Written discovery and depositions are now underway. This matter is set for trial beginning November 7, 2011, and we are unable to predict the outcome of the law suit.

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, 2010.

Item 5.  Other Information.

For the twelve months ended June 30, 2011, our ratio of earnings to fixed charges was 2.78x.  See Exhibit (12) hereto.

Item 6.  Exhibits.

(a)Exhibits.

(4) Thirty-seventh Supplemental Indenture, dated June 9, 2011, amending and supplementing the Indenture of Mortgage and Deed of Trust dated as of September 1, 1944, as amended and supplemented, among the Company, as issuer, and The Bank of New York Mellon Trust Company, N.A. (successor to Harris Trust and Savings Bank) and UMB Bank & Trust, N.A. (successor to State Street Bank and Trust Company of Missouri, N.A.), as trustees (Incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K dated June 9, 2011 and filed June 10, 2011, 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.*

(101) The following financial information from The Empire District Electric Company’s Quarterly Report on Form 10-Q for the period ended June 30, 2011, filed with the SEC on August 8, 2011, formatted in Extensible Business Reporting Language (XBRL): (i) the Consolidated Statements of Income for the three, six and twelve month periods ended June 30, 2011 and 2010, (ii) the Consolidated Balance Sheets at June 30, 2011 and December 31,

61

2010, (iii) the Consolidated Statements of Cash Flows for the six-month periods ended June 30, 2011 and 2010, and (iv) Notes to Consolidated Financial Statements.**

*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.

**Pursuant to Rule 406T of Regulation S-T, the XBRL related information in Exhibit 101 to this Quarterly Report on Form 10-Q shall not be deemed to be filed by the Company for purposes of Section 18 or any other provision of the Exchange Act of 1934, as amended.

62

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/ Laurie A. Delano
		Laurie A. Delano
		Vice President — Finance and Chief Financial Officer
	By	/s/ Robert W. Sager
		Robert W. Sager
		Controller, Assistant Secretary and Assistant Treasurer
August 8, 2011

63