Empire District Electric (EDE) 10-Q 2011 Q1 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 March 31, 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 April 29, 2011, 41,776,682 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	6
	c.	Consolidated Balance Sheets	7
	d.	Consolidated Statements of Cash Flows	9
	e.	Notes to Consolidated Financial Statements	10
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		29
	Executive Summary		29
	Results of Operations		31
	Rate Matters		41
	Competition		44
	Liquidity and Capital Resources		44
	Contractual Obligations		48
	Dividends		48
	Off-Balance Sheet Arrangements		49
	Critical Accounting Policies		49
	Recently Issued Accounting Standards		49
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		49
Item 4.	Controls and Procedures		51
Part II -	Other Information:
Item 1.	Legal Proceedings		52
Item 1A.	Risk Factors		52
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds - (none)
Item 3.	Defaults Upon Senior Securities - (none)
Item 5.	Other Information		52
Item 6.	Exhibits		52
	Signatures		53

2

FORWARD LOOKING STATEMENTS

Certain matters discussed in this quarterly report are “forward-looking statements” intended to qualify for the safe harbor from liability established by the Private Securities Litigation Reform Act of 1995. Such statements address or may address future plans, objectives, expectations and events or conditions concerning various matters such as capital expenditures, earnings, pension and other costs, competition, litigation, our construction program, our generation plans, our financing plans, potential acquisitions, rate and other regulatory matters, liquidity and capital resources and accounting matters. Forward-looking statements may contain words like “anticipate”, “believe”, “expect”, “project”, “objective” or similar expressions to identify them as forward-looking statements. Factors that could cause actual results to differ materially from those currently anticipated in such statements include:

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

·the amount, terms and timing of rate relief we seek and related matters;

·the cost and availability of purchased power and fuel, and the results of our activities (such as hedging) to reduce the volatility of such costs;

·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;

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

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

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

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

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

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

·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 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;

·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;

·competition, including the regional SPP energy imbalance market;

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

·changes in accounting requirements, including the potential consequences of International Financial Reporting Standards being required for U.S. SEC registrants rather than U.S. GAAP;

·the performance of our pension assets and other post employment benefit plan assets and the resulting impact on our related funding commitments; 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
	March 31,
	2011			2010
	(000’s except per share amounts)
Operating revenues:
Electric	$	127,934		$	113,600
Gas	20,989			24,560
Water	426			433
Other	1,379			1,300
	150,728			139,893
Operating revenue deductions:
Fuel and purchased power	54,217			50,684
Cost of natural gas sold and transported	12,040			15,109
Regulated operating expenses	19,715			18,917
Other operating expenses	475			488
Maintenance and repairs	9,242			7,807
Depreciation and amortization	17,333			13,185
Provision for income taxes	7,269			9,889
Other taxes	8,589			7,736
	128,880			123,815
Operating income	21,848			16,078
Other income and (deductions):
Allowance for equity funds used during construction	—			1,741
Interest income	23			70
Benefit/(provision) for other income taxes	24			(46		)
Other - non-operating expense, net	(285		)	(247		)
	(238		)	1,518
Interest charges:
Long-term debt	10,633			10,484
Trust preferred securities	—			1,063
Short-term debt	31			245
Allowance for borrowed funds used during construction	(23		)	(2,414		)
Other	(953		)	(368		)
	9,688			9,010
Net income	$	11,922		$	8,586
Weighted average number of common shares outstanding - basic	41,665			38,601
Weighted average number of common shares outstanding — diluted	41,707			38,646
Total earnings per weighted average share of common stock — basic and diluted	$	0.29		$	0.22
Dividends declared 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)

	Twelve Months Ended
	March 31,
	2011			2010
	(000’s except per share amounts)
Operating revenues:
Electric	$	497,245		$	440,370
Gas	47,314			53,787
Water	1,797			1,772
Other	5,754			5,117
	552,110			501,046
Operating revenue deductions:
Fuel and purchased power	202,831			185,922
Cost of natural gas sold and transported	23,545			31,402
Regulated operating expenses	80,090			74,502
Other operating expenses	1,937			1,879
Maintenance and repairs	38,206			33,152
Depreciation and amortization	62,804			52,006
Provision for income taxes	27,850			23,927
Other taxes	28,582			26,338
	465,845			429,128
Operating income	86,265			71,918
Other income and (deductions):
Allowance for equity funds used during construction	2,797			6,542
Interest income	129			211
Benefit/(provision) for other income taxes	6			(281		)
Other - non-operating expense, net	(1,077		)	(785		)
	1,855			5,687
Interest charges:
Long-term debt	42,107			42,935
Trust preferred securities	1,027			4,250
Short-term debt	417			790
Allowance for borrowed funds used during construction	(3,245		)	(8,142		)
Other	(2,918		)	(1,196		)
	37,388			38,637
Net income	$	50,732		$	38,968
Weighted average number of common shares outstanding - basic	41,300			36,042
Weighted average number of common shares outstanding — diluted	41,324			36,065
Total earnings per weighted average share of common stock — basic and diluted	$	1.23		$	1.08
Dividends declared per share of common stock	$	1.28		$	1.28

See accompanying Notes to Consolidated Financial Statements.

5

THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	Three Months Ended
	March 31,
	2011		2010
	($-000’s)
Net income	$	11,922	$	8,586
Reclassification adjustments for (gain)/loss included in net income or reclassified to regulatory asset or liability	—		—
Net change in fair market value of open derivative contracts for period	—		(6,001		)
Income taxes	—		2,286
Comprehensive income	$	11,922	$	4,871

	Twelve Months Ended
	March 31,
	2011			2010
	($-000’s)
Net income	$	50,732		$	38,968
Reclassification adjustments for loss included in net income or reclassified to regulatory asset or liability	5,814			8,643
Net change in fair market value of open derivative contracts for period	(361		)	(6,244		)
Income taxes	(2,078		)	(914		)
Comprehensive income	$	54,107		$	40,453

See accompanying Notes to Consolidated Financial Statements.

6

THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS (UNAUDITED)

	March 31, 2011		December 31, 2010
	($-000’s)
Assets
Plant and property, at original cost:
Electric	$	2,009,203	$	2,001,142
Natural gas	63,762		63,581
Water	11,210		11,128
Other	32,548		32,264
Construction work in progress	17,239		9,337
	2,133,962		2,117,452
Accumulated depreciation and amortization	612,854		598,363
	1,521,108		1,519,089
Current assets:
Cash and cash equivalents	7,805		14,499
Accounts receivable — trade, net	45,394		41,380
Accrued unbilled revenues	16,511		23,595
Accounts receivable — other	22,463		25,445
Fuel, materials and supplies	44,557		45,557
Unrealized gain in fair value of derivative contracts	80		39
Prepaid expenses and other	4,847		5,649
Regulatory assets	3,606		4,974
	145,263		161,138
Noncurrent assets and deferred charges:
Regulatory assets	190,573		189,404
Goodwill	39,492		39,492
Unamortized debt issuance costs	9,076		9,257
Unrealized gain in fair value of derivative contracts	480		194
Other	3,072		2,737
	242,693		241,084
Total Assets	$	1,909,064	$	1,921,311

(Continued)

See accompanying Notes to Consolidated Financial Statements.

7

THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS (UNAUDITED) (Continued)

	March 31, 2011		December 31, 2010
	($-000’s)
Capitalization and Liabilities
Common stock, $1 par value, 41,745,638 and 41,576,869 shares issued and outstanding, respectively	$	41,746	$	41,577
Capital in excess of par value	614,359		610,579
Retained earnings	4,053		5,468
Total common stockholders’ equity	660,158		657,624
Long-term debt (net of current portion):
Obligations under capital lease	4,928		4,995
First mortgage bonds and secured debt	488,428		488,577
Unsecured debt	199,518		199,500
Total long-term debt	692,874		693,072
Total long-term debt and common stockholders’ equity	1,353,032		1,350,696
Current liabilities:
Accounts payable and accrued liabilities	44,330		58,820
Current maturities of long-term debt	896		881
Short-term debt	11,000		24,000
Customer deposits	11,258		11,061
Interest accrued	12,313		6,004
Other current liabilities	954		578
Unrealized loss in fair value of derivative contracts	1,190		760
Taxes accrued	6,985		3,935
Regulatory liabilities	495		1,243
	89,421		107,282
Commitments and contingencies (Note 7)
Noncurrent liabilities and deferred credits:
Regulatory liabilities	95,978		87,579
Deferred income taxes	220,715		212,003
Unamortized investment tax credits	19,517		19,597
Pension and other postretirement benefit obligations	80,949		93,405
Unrealized loss in fair value of derivative contracts	2,638		3,564
Other	46,814		47,185
	466,611		463,333
Total Capitalization and Liabilities	$	1,909,064	$	1,921,311

See accompanying Notes to Consolidated Financial Statements.

8

THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

	Three Months Ended
	March 31,
	2011			2010
	($-000’s)
Operating activities:
Net income	$	11,922		$	8,586
Adjustments to reconcile net income to cash flows from operating activities:
Depreciation and amortization	22,796			14,909
Pension and other postretirement benefit costs, net of contributions	(11,768		)	1,652
Deferred income taxes and investment tax credit, net	8,537			4,249
Allowance for equity funds used during construction	���			(1,741		)
Stock compensation expense	867			889
Cash flows impacted by changes in:
Accounts receivable and accrued unbilled revenues	6,052			8,426
Fuel, materials and supplies	1,001			2,093
Prepaid expenses, other current assets and deferred charges	(4,070		)	(3,170		)
Accounts payable and accrued liabilities	(15,066		)	(18,451		)
Interest, taxes accrued and customer deposits	9,556			16,150
Accumulated provision — rate refunds	375			—
Other liabilities and other deferred credits	3,829			3,243
Net cash provided by operating activities	34,031			36,835
Investing activities:
Capital expenditures — regulated	(16,957		)	(33,755		)
Capital expenditures and other investments — non-regulated	(292		)	(1,052		)
Net cash used in investing activities	(17,249		)	(34,807		)
Financing activities:
Proceeds from issuance of common stock, net of issuance costs	3,073			32,555
Net short-term repayments	(13,000		)	(21,500		)
Dividends	(13,337		)	(12,324		)
Other	(212		)	(402		)
Net cash used in financing activities	(23,476		)	(1,671		)
Net (decrease)/increase in cash and cash equivalents	(6,694		)	357
Cash and cash equivalents at beginning of period	14,499			5,620
Cash and cash equivalents at end of period	$	7,805		$	5,977

See accompanying Notes to Consolidated Financial Statements.

9

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

There were no recently issued or newly proposed accounting standards in the first quarter of 2011 required to be disclosed.

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, is specific to Iatan 1 and Iatan 2 and allows us to defer certain charges as regulatory assets. These deferred charges include depreciation, operations and maintenance and carrying costs related to operation of the facilities until the facilities are ultimately included in our rates. The regulatory plan also requires us to continue to defer the fuel and purchased power expense impacts of Iatan 2, which were approximately $5.9 million as of March 31, 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 recently completed Missouri rate case, construction accounting was approved for Plum Point, which met its in-service criteria on August 13, 2010. Construction accounting deferred charges for Plum Point applies only to costs incurred subsequent to February 28, 2010. All of these deferrals begin at the in-service dates and will be amortized over the life of the plants once they are included in our rates, which for Iatan 2 and Plum Point, we estimate to be upon completion of our Missouri rate case filed on September 28, 2010. 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, expected to be an abbreviated rate case that will be filed by mid-summer. 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 few changes to regulatory assets and liabilities regarding their rate base inclusion or amortizable lives since December 31, 2010.

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

10

Regulatory Assets and Liabilities

	March 31, 2011		December 31, 2010
Regulatory Assets:
Under recovered electric fuel and purchased power costs — current	$	3,606	$	4,974
Regulatory assets, current(1)	3,606		4,974
Pension and other postretirement benefits(2)	91,718		92,192
Income taxes	50,188		50,188
Unamortized loss on reacquired debt	12,727		13,099
Unamortized loss on interest rate derivative	1,698		1,776
Asbury five-year maintenance	833		948
Storm costs(3)	6,717		7,733
Deferred construction accounting costs(4)	13,909		10,521
Asset retirement obligation	3,449		3,412
Under recovered purchased gas costs — gas segment	—		439
Unsettled derivative losses — electric segment	2,969		3,166
Customer programs	2,363		2,119
System reliability — vegetation management	3,517		3,338
Other	485		473
Regulatory assets, long-term	190,573		189,404
Total	$	194,179	$	194,378

	March 31, 2011		December 31, 2010
Regulatory Liabilities:
Over recovered purchased gas costs — gas segment - current	$	495	$	1,243
Regulatory liabilities, current(1)	495		1,243
Cost of removal	65,860		62,756
Income taxes	12,620		12,715
Unamortized gain on interest rate derivative	3,839		3,881
Pension and other postretirement benefits(5)	4,924		4,604
Deferred construction accounting costs — fuel	5,917		3,126
Over recovered electric fuel and purchased power costs(6)	516		155
Over recovered purchased gas costs — gas segment	2,146		—
Other	156		342
Regulatory liabilities, long-term	95,978		87,579
Total	$	96,473	$	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 pension and OPEB related acquisition costs. Approximately $0.1 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 March 31, 2011	Deferred Carrying Charges		Deferred O&M	Depreciation	Total
Iatan 1	$	2,766	1,382	1,675	$	5,823
Iatan 2	$	2,925	2,965	1,949	$	7,839
Plum Point	$	48	119	80	$	247
Total					$	13,909

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 $0.5 million as a result of ratemaking treatment.

(6) Primarily consists of Missouri over recovered fuel and purchased power costs for the current accumulation period September 2010 through February 2011.

11

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

		March 31,		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	80		39
	Non-current assets and deferred charges	52		117
Natural gas contracts, electric segment	Current assets	—		—
	Non-current assets and deferred charges	428		77
Total derivatives assets		$	560	$	233

		March 31,		December 31,
LIABILITY DERIVATIVES		2011		2010
Non-designated as hedging instruments due to regulatory accounting	Balance Sheet Classification	Fair Value		Fair Value
Natural gas contracts, gas segment	Current liabilities	37		252
	Non-current liabilities and deferred credits	2		2
Natural gas contracts, electric segment	Current liabilities	1,153		508
	Non-current liabilities and deferred credits	2,636		3,562
Total derivatives liabilities		$	3,828	$	4,324

Electric

At March 31, 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 March 31, (in thousands):

12

	Income Statement	Amount of Gain / (Loss) Reclassed from OCI into
	Classification of	Income (Effective portion)
Derivatives in Cash Flow Hedging	Gain / (Loss) on	Three Months Ended				Twelve Months Ended
Relationships - Electric Segment(1)	Derivative	2011		2010		2011			2010
Commodity contracts	Fuel and purchased power expense	$	—	$	—	$	(5,814	)	$	(8,643	)
Total Effective - Electric Segment		$	—	$	—	$	(5,814	)	$	(8,643	)

		Amount of Gain / (Loss) Recognized in OCI on
	Statement of	Derivative (Effective portion)
Derivatives in Cash Flow Hedging	Comprehensive	Three Months Ended					Twelve Months Ended
Relationships - Electric Segment(1)	Income	2011		2010			2011			2010
Commodity contracts	Fuel and purchased power expense	$	—	$	(6,001	)	$	(361	)	$	(6,244	)
Total Effective - Electric Segment		$	—	$	(6,001	)	$	(361	)	$	(6,244	)

(1) Effective December 2010, all remaining cash flow hedges entered into prior to September 1, 2008 were de-designated and recorded as a regulatory asset subject to the fuel recovery clause.

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 March 31, 2011 and 2010, respectively.

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 March 31, (in thousands):

		Amount of Gain / (Loss) Recognized on Balance
Non-Designated Hedging Instruments —	Balance Sheet	Sheet
Due to Regulatory Accounting	Classification of Gain/	Three Months Ended					Twelve Months Ended
Electric Segment	(Loss) on Derivative	2011		2010			2011			2010
Commodity contracts	Regulatory (assets)/liabilities	$	632	$	(1,292	)	$	(2,037	)	$	(1,567	)
Total Electric Segment		$	632	$	(1,292	)	$	(2,037	)	$	(1,567	)

		Amount of Gain / (Loss) Recognized in Income
Non-Designated Hedging Instruments —	Statement of Operations	on Derivative
Due to Regulatory Accounting	Classification of Gain /	Three Months Ended					Twelve Months Ended
Electric Segment	(Loss) on Derivative	2011		2010			2011			2010
Commodity contracts	Fuel and purchased power expense	$	160	$	(262	)	$	(592	)	$	(1,415	)
Total Electric Segment		$	160	$	(262	)	$	(592	)	$	(1,415	)

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 April 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	85	%	2,317,500	1,790,000	$	5.725
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	4	%	0	400,000	$	5.500

13

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%

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 March 31, 2011, we had 0.1 million Dths in storage on the three pipelines that serve our customers. This represents 4.3% 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 March 31, 2011 (in thousands).

Season	Minimum % Hedged	Dth Hedged — Financial	Dth Hedged — Physical	Actual % Hedged
Current	50%	480,000	246,000	11	%
Second	Up to 50%	310,000	0	5	%
Third	Up to 20%	0	0	0	%
Total		790,000	246,000

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 March 31, (in thousands).

	Balance Sheet	Amount of Gain / (Loss)
Non-Designated Hedging	Classification of	Recognized on Balance Sheet
Instruments Due to Regulatory	Gain or (Loss) on	Three Months Ended						Twelve Months Ended
Accounting — Gas Segment	Derivative	2011			2010			2011			2010
Commodity contracts	Regulatory (assets)/ liabilities	$	(96	)	$	(127	)	$	(595	)	$	1,040
Total - Gas Segment		$	(96	)	$	(127	)	$	(595	)	$	1,040

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

14

contingent features that are in a liability position on March 31, 2011 is $0.4 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 March 31, 2011, we would have been required to post $0.4 million of collateral with one of our counterparties. On March 31, 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) 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 March 31, 2011 and December 31, 2010.

($ in 000’s)

	Fair Value Measurements at Reporting Date Using
				Quoted Prices in Active			Significant Other		Significant
				Markets for Identical			Observable		Unobservable
	Liabilities			Liabilities			Inputs		Inputs
Description	at Fair Value			(Level 1)			(Level 2)		(Level 3)
	March 31, 2011
Net derivative liabilities*	$	(3,268	)	$	(3,268	)	$	—	$	—
	December 31, 2010
Net derivative liabilities*	$	(4,091	)	$	(4,091	)	$	—	$	—

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

The following table presents the net fair value on a recurring basis using significant unobservable inputs (Level 3) during the twelve months ended periods March 31, 2011 and 2010. There were no such inputs for the quarterly periods.

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, April 1,	$	—	$	3,752
Total gains or (losses) (realized/unrealized)
Included in earnings (or changes in net assets)
Included in comprehensive income	—		718
Purchases, issuances, and settlements
Transfers into and (out of) Level 3(2) (3)	—		(4,470		)
Ending Balance, March 31,	$	—	$	—
Changes in unrealized gains relating to assets still held at reporting date	$	—	$	—

(1) Net derivatives at March 31, 2011 and 2010 included no derivative assets or derivative liabilities.

15

(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 March 31, 2011, was $689 million compared to a fair market value of approximately $695 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 March 31, 2011 or that will be realizable in the future.

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 revolving credit facility. This agreement extends 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 March 31, 2011, we are in compliance with these ratios. Our total indebtedness is 51.6% of our total capitalization as of March 31, 2011 and our EBITDA is 5.1 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 March 31, 2011. However, $11.0 million was used to back up our outstanding commercial paper.

Note 7— Commitments and Contingencies

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

16

Coal, Natural Gas and Transportation Contracts

(in millions)	Firm physical gas and transportation contracts		Coal and coal transportation contracts
April 1, 2011 through December 31, 2011	$	28.9	$	29.7
January 1, 2012 through December 31, 2013	56.9		54.1
January 1, 2014 through December 31, 2015	29.4		34.0
January 1, 2016 and beyond	25.8		14.5

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 beginning 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 $41.9 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 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. (formerly known as PPM Energy), to purchase the energy generated at the 150-megawatt Elk River Windfarm located in Butler County, Kansas, which was declared commercial on December 15, 2005. Although these agreements are considered operating leases under Generally Accepted Accounting Principles (GAAP), payments for these wind agreements are recorded as purchased power expenses, and, because of the contingent nature of these payments, are not included in our operating lease obligations.

New Construction

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

17

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 March 31, 2011 was $230.8 million plus AFUDC of $19.1 million. Current projections estimate $9.2 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.

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, effective September 10, 2010. The construction costs noted above for Iatan 2, as well as the costs we incurred and began receiving effective September 10, 2010 for Iatan 1 and Plum Point, are subject to a prudency review in this case.

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. We will file a general rate case within six months of the commercial operation date of Iatan 2 to replace the CRR with permanent rates.

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 will defer depreciation and operating and maintenance expense on both Plum Point and Iatan 2 from their respective in-service dates until the effective date for rates from the next Kansas case, expected to be an abbreviated rate case that will be filed by mid-summer. These deferrals will be recovered over a 3-5 year period as determined in that next case.

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 to become effective with customer bills rendered after that date.

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

18

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.

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

In 2010, our SO2 emissions exceeded the annual allocations. This deficit was covered by our banked allowances. When our SO2 allowance bank is exhausted, currently estimated to be early 2012, we will need to purchase additional SO2 allowances. The longer term solution will be to either continue purchasing SO2 allowances until a Flue Gas Desulphurization (FGD) scrubber system at our Asbury Plant can be constructed or to purchase SO2 allowances to meet our annual emission requirements. Based on current and projected SO2 allowance prices and high-level estimated FGD scrubber construction costs (discussed below) and absent other, more stringent regulatory requirements, such as the proposed Clean Air Transport Rule (CATR) and Power Plant Mercury and Air Toxics Rule (Toxics Rule) discussed below, it will likely be more economical for us to purchase SO2 allowances than to build a scrubber at the Asbury Plant. If we were to purchase SO2 allowances, we would expect their cost to be fully recoverable in our rates.

NOx Emissions

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

Ozone, also called ground level smog, is formed by the mixing of NOx and Volatile Organic Compounds in the presence of sunlight. On January 6, 2010, the EPA proposed to lower the primary National Ambient Air Quality Standard (NAAQS) for ozone designed to protect public health and to set a secondary NAAQS for ozone designed to protect sensitive vegetation and ecosystems. The EPA is expected to issue final standards by July 31, 2011. Once final standards are set, states will be required to develop State Implementation Plans (SIPs) which reflect these standards.

Clean Air Interstate Rule (CAIR) and Clean Air Transport Rule (CATR)

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

19

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

The CAIR requires covered states (including Missouri and Arkansas) to develop SIPs to comply with specific NOx and SO2 state-wide annual budgets. Missouri and Arkansas have approved SIPs and, based on these SIPs, we believe we will have excess NOx allowances for 2010 which will be banked for future use. However, SO2 allowances must be utilized at a 2:1 ratio for our Missouri units as compared to our non-CAIR Kansas units beginning in 2010. As a result, based on current SO2 allowance usage projections, we expect to exhaust our banked allowances by early 2012 and, as discussed above, will need to purchase additional SO2 allowances. Longer term solutions could include the purchase of SO2 allowances until such time as a scrubber can be constructed.

In order to meet CAIR requirements and as a requirement for the air permit for Iatan 2, a Selective Catalytic Reduction system (SCR), FGD scrubber system and baghouse were installed at our jointly-owned Iatan 1 plant and an 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.

On July 6, 2010, the EPA published a proposed CAIR replacement rule entitled the Clean Air Transport Rule (CATR). As proposed, the CATR would include Kansas under the annual and ozone season NOx and the SO2 programs. Missouri would be dropped from the ozone season NOx program while Arkansas would remain in the ozone season NOx program. The beginning date of regulation for the proposed CATR is 2012. The final CATR is expected to be issued by the EPA in July 2011. The proposed rule requires a 71% reduction in SO2 and a 52% reduction in NOx from 2005 levels by 2014. We do not expect significant impacts on our operations because of new NOx requirements in CATR. We cannot accurately estimate the cost of any non-final regulation or predict its precise timing and its impact on our operations at this time. To address SO2 compliance plans range from purchasing additional emission allowances 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.

Power Plant Mercury and Air Toxics Rule (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 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. We completed the ICR for Asbury and Riverton Units 7 and 8 and submitted them to the EPA on March 31, 2010. KCP&L completed and submitted the Iatan Unit 1 ICR. 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 issued its pre-publication proposed Toxics Rule on March 16, 2011 and is scheduled to finalize this regulation by November 16, 2011. Absent a successful legal challenge or changes to applicable legislation, we expect the Toxics Rule regulation of HAPs in combination with CATR 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 switch them 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.

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).

20

On September 22, 2009, the EPA issued the final Mandatory Reporting of Greenhouse Gases Rule under the CAA which requires power generating and certain other facilities, including EDG that equal or exceed an emission threshold of 25,000 metric tons of CO2e to report GHGs to the EPA annually commencing in September 2011. We will report our GHG emissions as required to the EPA in 2011 for EDE. EDG is not required to submit its GHG emissions until 2012.

On December 7, 2009, responding to a 2007 US Supreme Court decision that determined that GHGs constitute “air pollutants” under the CAA, the EPA issued its final finding that GHGs threaten both the public health and the public welfare. This “endangerment” finding does not itself trigger any EPA regulations, but is a necessary predicate for the EPA to proceed with regulations to control GHGs. On May 13, 2010, the EPA issued under the CAA its final Prevention of Significant Deterioration and Title V Greenhouse Gas Tailoring Rule (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 July 26, 2011 and to issue final GHG NSPS standards by May 26, 2012.

Litigation aimed at controlling GHG emissions has also increased. For example, recently the U.S. Court of Appeals for the Second Circuit has ruled that certain public and private parties can pursue claims that GHG emissions constitute a public nuisance and can seek to recover alleged related damages. The U.S. Supreme Court agreed to review this decision and heard oral arguments on April 19, 2011. A decision is expected later this year. In contrast, in May 2010, the full U.S. Court of Appeals for the Fifth Circuit took action which left standing the lower court’s dismissal of a nuisance claim similar to those upheld by the Second Circuit, which as noted above, is now before the U.S. Supreme Court.

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

21

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 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 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. 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. It is anticipated that the final regulation will be published in 2011. 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. This preliminary estimate will likely change based on the final CCR rule and design requirements reach final forms.  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 have received preliminary draft reports on the Asbury and the Riverton impoundments. The reports are currently under final review by the EPA and our comments have been submitted. We are not currently in a position to estimate what additional actions if any will result from the EPA’s inspections.

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.

22

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. 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. is pending in the Missouri Western District Court of Appeals. Renewable energy standard compliance rules were published by the MPSC on July 7, 2010. Kansas established a renewable portfolio standard (RPS) in May 2009 which was approved October 27, 2010, effective November 19, 2010. Its final rulemaking was released in November 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 retirement 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 March 31,
	Pension						SERP						OPEB
	2011			2010			2011			2010			2011			2010
Service cost	$	1,393		$	1,273		$	20		$	17		$	626		$	509
Interest cost	2,591			2,550			41			39			1,130			1,063
Expected return on plan assets	(2,680		)	(2,483		)	—			—			(1,050		)	(966		)
Amortization of prior service cost (1)	133			133			(2		)	(2		)	(253		)	(253		)
Amortization of net actuarial loss (1)	1,353			1,033			33			32			500			344
Net periodic benefit cost	$	2,790		$	2,506		$	92		$	86		$	953		$	697

	Twelve months ended March 31,
	Pension						SERP						OPEB
	2011			2010			2011			2010			2011			2010
Service cost	$	5,007		$	4,894		$	73		$	62		$	2,254		$	1,885
Interest cost	10,156			9,989			155			150			4,396			3,984
Expected return on plan assets	(10,044		)	(10,261		)	—			—			(3,927		)	(3,849		)
Amortization of prior service cost (1)	531			586			(8		)	(8		)	(1,011		)	(1,011		)
Amortization of net actuarial loss (1)	4,315			3,461			98			103			1,655			981
Net periodic benefit cost	$	9,965		$	8,669		$	318		$	307		$	3,367		$	1,990

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

23

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 and on April 13, 2011, we made an additional $2.1 million contribution. We estimate additional quarterly contributions of approximately $2.0 million will be required in July and 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 March 31 (in thousands):

	Three Months Ended				Twelve Months Ended
	2011		2010		2011		2010
Compensation expense	$	741	$	798	$	3,136	$	2,510
Tax benefit recognized	271		288		1,143		898

Activity for our various stock plans for the three months ended March 31, 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:

	Fair Value of Grants Outstanding at March 31,
	2011	2010
Risk-free interest rate	0.61% to 1.15%	0.32% to 1.45%
Expected volatility of Empire stock	26.1%	28.6%
Expected volatility of peer group stock	21.1% to 82.2%	22.2% to 81.5%
Expected dividend yield on Empire stock	6.3%	7.3%
Expected forfeiture rates	3%	3%
Plan cycle	3 years	3 years
Fair value percentage	97.0% to 143.0%	104.0% to 125.0%
Weighted average fair value per share	$27.20	$20.76

Non-vested restricted stock awards (based on target number) as of March 31, 2011 and 2010 and changes during the three months ended March 31, 2011 and 2010 were as follows:

24

	2011				2010
	Number of shares		Weighted Average Grant Date Price		Number of shares		Weighted Average Grant Date Price
Outstanding 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 March 31,	37,400		$	19.28	47,500		$	19.86

At March 31, 2011, there was $0.3 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 March 31, 2011 and 2010, under a Black-Scholes methodology. The assumptions used in the valuations are shown below:

	Fair Value of Grants Outstanding at March 31,
	2011	2010
Risk-free interest rate	0.45% to 2.39%	0.91% to 1.85%
Dividend yield	6.3%	7.3%
Expected volatility	23.0%	23.0%
Expected life in months	78	78
Market value	$ 21.79	$ 18.02
Weighted average fair value per option	$ 1.94	$ 0.85

	2011			2010
		Weighted			Weighted
		Average			Average
	Options	Exercise Price		Options	Exercise Price
Outstanding at January 1,	267,400	$	21.69	232,600	$	22.19
Granted	—	$	—	34,800	$	18.36
Exercised	—	—		—	—
Outstanding at March 31,	267,400	$	21.69	267,400	$	21.69
Exercisable at March 31,	205,600	$	22.73	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 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 March 31, 2011 and 2010:

	2011	2010
Aggregate intrinsic value (in millions)	$0.2	$0.0
Weighted-average remaining contractual life of outstanding options	5.8 years	6.8 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	$0.1	$0.3
Recognition period	1 to 2 years	1 to 3 years

25

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	Fair Value
Outstanding at January 1,	—	$	—
Granted	10,200	$	18.13
Vested	—	—
Outstanding at March 31,	10,200	$	17.95

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.

Note 10 - Regulated Operating Expense

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 March 31):

	Three Months Ended		Three Months Ended		Twelve Months Ended		Twelve Months Ended
	2011		2010		2011		2010
Electric transmission and distribution expense	$	3,823	$	2,827	$	13,992	$	11,300
Natural gas transmission and distribution expense	562		532		2,225		2,167
Power operation expense (other than fuel)	2,677		2,904		11,129		12,156
Customer accounts and assistance expense	2,536		2,919		11,234		11,065
Employee pension expense (1)	1,844		1,464		6,279		5,661
Employee healthcare plan (1)	1,621		1,550		7,001		6,142
General office supplies and expense	2,898		2,676		11,807		10,485
Administrative and general expense	3,647		3,416		13,126		12,628
Allowance for uncollectible accounts	82		600		3,133		2,778
Miscellaneous expense	25		29		164		120
Total	$	19,715	$	18,917	$	80,090	$	74,502

(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.

26

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

For the quarter ended March 31,

	2011
($-000’s)	Electric		Gas		Other		Eliminations			Total
Statement of Income Information
Revenues	$	128,360	$	20,989	$	1,527	$	(148	)	$	150,728
Depreciation and amortization	16,028		873		432		—			17,333
Federal and state income taxes	5,633		1,381		231		—			7,245
Operating income	18,276		3,195		377		—			21,848
Interest income	22		71		—		(70		)	23
Interest expense	8,801		977		3		(70		)	9,711
Income from AFUDC (debt and equity)	23		—		—		—			23
Net income	9,301		2,246		375		—			11,922
Capital Expenditures	$	16,850	$	340	$	367	$	—		$	17,557

For the quarter ended March 31,

	2010
($-000’s)	Electric		Gas		Other		Eliminations			Total
Statement of Income Information
Revenues	$	114,033	$	24,560	$	1,449	$	(149	)	$	139,893
Depreciation and amortization	12,301		509		375		—			13,185
Federal and state income taxes	8,281		1,440		214		—			9,935
Operating income	12,485		3,235		358		—			16,078
Interest income	72		126		—		(128		)	70
Interest expense	10,559		983		10		(128		)	11,424
Income from AFUDC (debt and equity)	4,155		—		—		—			4,155
Net income	5,924		2,314		348		—			8,586
Capital Expenditures	$	29,236	$	288	$	1,351	$	—		$	30,875

For the twelve months ended March 31,

	2011
($-000’s)	Electric		Gas		Other		Eliminations			Total
Statement of Income Information
Revenues	$	499,042	$	47,314	$	6,346	$	(592	)	$	552,110
Depreciation and amortization	57,710		3,397		1,697		—			62,804
Federal and state income taxes	25,278		1,561		1,005		—			27,844
Operating income	78,319		6,287		1,659		—			86,265
Interest income	148		348		—		(367		)	129
Interest expense	37,040		3,934		26		(367		)	40,633
Income from AFUDC (debt and equity)	6,023		19		—		—			6,042
Net income	46,564		2,534		1,634		—			50,732
Capital Expenditures	$	87,659	$	5,293	$	1,785	$	—		$	94,737

27

For the twelve months ended March 31,

	2010
($-000’s)	Electric		Gas		Other		Eliminations			Total
Statement of Income Information
Revenues	$	442,142	$	53,787	$	5,709	$	(592	)	$	501,046
Depreciation and amortization	48,507		2,024		1,475		—			52,006
Federal and state income taxes	22,394		969		845		—			24,208
Operating income	65,202		5,254		1,462		—			71,918
Interest income	222		371		—		(382		)	211
Interest expense	43,174		3,946		41		(382		)	46,779
Income from AFUDC (debt and equity)	14,683		1		—		—			14,684
Net Income	36,158		1,436		1,374		—			38,968
Capital Expenditures	$	145,684	$	2,074	$	2,069	$	—		$	149,827

As of March 31, 2011

($-000’s)	Electric		Gas(1)		Other		Eliminations			Total
Balance Sheet Information
Total assets	$	1,831,008	$	143,020	$	22,965	$	(87,929	)	$	1,909,064

(1) Includes goodwill of $39,492.

As of December 31, 2010

($-000’s)	Electric		Gas(1)		Other		Eliminations			Total
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 increases in our provision for income taxes (in millions) and our consolidated effective federal and state income tax rates for the applicable periods ended March 31,:

	Three Months Ended						Twelve Months Ended
	2011			2010			2011			2010
Consolidated provision for income taxes	$	7.3		$	9.9		$	27.8		$	24.2
Consolidated effective federal and state income tax rates	37.8		%	53.6		%	35.4		%	38.3		%

The effective tax rates for the first quarter of 2011 and the twelve months ended March 31, 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 is enacted. As a result, in the first quarter of 2010, we recorded a one-time non-cash charge of approximately $2.1 million to income taxes to reflect the impact of this change, 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

28

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. Amortization of the remaining regulatory tax asset will begin in 2011 or 2012, which is also when we expect to be able to request rate recovery of the asset.

We received $26.6 million in 2010 from the Southwest Power Administration (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 filed a request 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 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 March 31, 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 March 31, 2011, our gross operating revenues were derived as follows:

Electric segment sales*	90.4	%
Gas segment sales	8.6
Other segment sales	1.0

*Sales from our electric segment include 0.3% from the sale of water.

Earnings

During the first quarter of 2011, basic and diluted earnings per weighted average share of common stock were $0.29 on net income of $11.9 million, as compared to $0.22 on net income of $8.6 million in the first quarter of 2010. For the twelve months ended March 31, 2011, basic and diluted earnings per weighted average share of common stock were $1.23 on net income of $50.7 million as compared to $1.08 on net income of $39.0 million for the twelve months ended March 31, 2010. The primary positive drivers for the first quarter of 2011 were increased electric revenues (due primarily to rate increases) and the change in effective tax rates when compared to the first quarter of 2010 when we had two non-cash charges that negatively impacted our effective tax rates. (See Note 12 of “Notes to Consolidated Financial Statements (Unaudited)”). The primary negative drivers for the first quarter of 2011 were decreased sales due to mild weather, increased depreciation expense and changes in AFUDC amounts. The primary positive drivers for the twelve months ended March 31, 2011 were increased electric revenues (due primarily to rate increases and favorable weather), the effect of the 2010 tax rates previously noted and decreased interest charges. The primary negative

29

drivers were increased depreciation expense, increased electric operations and maintenance expense, the dilutive effect of additional shares of common stock issued and changes in AFUDC amounts.

The table below sets forth a reconciliation of basic and diluted earnings per share between the three months and twelve months ended March 31, 2010 and March 31, 2011, which is a non-GAAP presentation. The economic substance behind our non-GAAP earnings per share (EPS) measure is to present the after tax impact of significant items and components of the statement of income on a per share basis before the impact of additional stock issuances.

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

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

	Three Months Ended			Twelve Months Ended
Earnings Per Share — 2010	$	0.22		$	1.08
Revenues
Electric on-system	$	0.20		$	0.89
Electric off — system and other	0.04			0.17
Gas	(0.06		)	(0.12		)
Water	—			—
Other	—			0.01
Expenses
Electric fuel and purchased power	(0.06		)	(0.31		)
Cost of natural gas sold and transported	0.05			0.15
Regulated — electric segment	(0.02		)	(0.12		)
Regulated —gas segment	0.01			0.02
Maintenance and repairs	(0.02		)	(0.10		)
Depreciation and amortization	(0.07		)	(0.20		)
Other taxes	(0.01		)	(0.04		)
Interest charges	0.03			0.11
AFUDC	(0.07		)	(0.16		)
Change in effective income tax rates	0.07			0.04
Other income and deductions	—			(0.01		)
Dilutive effect of additional shares issued	(0.02		)	(0.18		)
Earnings Per Share — 2011	$	0.29		$	1.23

Recent Activities

Regulatory Matters

Our rate cases, as we reported in our Annual Report on Form 10-K for the year ended December 31, 2010, remain unchanged except for a settlement approved by the Arkansas Public Service Commission (APSC) on April 12, 2011, with the new rates to become effective with customer bills rendered after that date. Our Missouri rate case, filed on September 28, 2010, remains unchanged. We will file a general rate case within six months of the commercial operation date of Iatan 2 to replace the two-phase Capital Reliability Rider (CRR) granted by the Oklahoma Corporation Commission (OCC) on August 30, 2010, with permanent rates. Our next Kansas case, expected to be an abbreviated rate case, will be filed by mid-summer. We are working to finalize the terms of the

30

settlement reached on September 15, 2010, with the FERC on our Generation Formula Rate (GFR) tariffs.

For additional information, see “Rate Matters” 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.

RESULTS OF OPERATIONS

The following discussion analyzes significant changes in the results of operations for the three-month and twelve-month periods ended March 31, 2011, compared to the same periods ended March 31, 2010.

The following table represents our results of operations by operating segment for the applicable periods ended March 31 (in millions):

	Three Months Ended				Twelve Months Ended
	2011		2010		2011		2010
Electric	$	9.3	$	5.9	$	46.6	$	36.2
Gas	2.2		2.3		2.5		1.4
Other	0.4		0.4		1.6		1.4
Net income	$	11.9	$	8.6	$	50.7	$	39.0

Electric Segment

Overview

Our electric segment income for the first quarter of 2011 was $9.3 million as compared to $5.9 million for the first quarter of 2010, an increase of $3.4 million, primarily due to the September 2010 Missouri rate increase and the July 2010 Kansas rate increase (discussed below).

Electric operating revenues comprised approximately 84.9% of our total operating revenues during the first quarter of 2011. Electric operating revenues for the first quarter of 2011 and 2010 were comprised of the following:

	2011		2010
Residential	46.4	%	47.5	%
Commercial	26.8		26.2
Industrial	13.0		12.4
Wholesale on-system	3.3		4.4
Wholesale off-system	6.2		5.5
Miscellaneous sources*	2.6		2.5
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 electric segment operating revenues by major customer class for on-system and off-system sales for the applicable periods ended March 31, were as follows:

31

kWh Sales

(in millions)

	First	First			12 Months	12 Months
	Quarter	Quarter	%		Ended	Ended	%
Customer Class	2011	2010	Change*		2011	2010	Change*
Residential	591.4	639.2	(7.5	)%	2,012.6	1,954.8	3.0	%
Commercial	375.7	385.7	(2.6	)	1,634.9	1,589.5	2.9
Industrial	237.0	231.0	2.6		1,013.1	982.9	3.1
Wholesale on-system	87.6	84.9	3.1		358.4	336.2	6.6
Other**	33.3	33.9	(1.8	)	125.8	125.1	0.6
Total on-system sales	1,325.0	1,374.7	(3.6	)	5,144.8	4,988.5	3.1
Off-system	257.9	182.5	41.3		873.5	564.6	54.7
Total kWh Sales	1,582.9	1,557.2	1.6		6,018.3	5,553.1	8.4

*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.

Electric Segment Operating Revenues

(in millions)

							12		12
	First		First				Months		Months
	Quarter		Quarter		%		Ended		Ended		%
Customer Class	2011		2010		Change*		2011		2010		Change*
Residential	$	59.4	$	54.0	10.0	%	$	210.3	$	185.8	13.2	%
Commercial	34.3		29.7		15.3		150.9		135.9		11.0
Industrial	16.7		14.1		18.3		72.3		65.2		10.8
Wholesale on-system	4.2		4.9		(14.2	)	18.5		18.4		0.6
Other**	3.3		2.9		15.0		12.7		11.7		8.8
Total on-system revenues	$	117.9	$	105.6	11.6		$	464.7	$	417.0	11.4
Off-system	7.9		6.2		27.8		24.6		16.6		48.3
Total Revenues from kWh Sales	125.8		111.8		12.5		489.3		433.6		12.9
Miscellaneous Revenues***	2.1		1.8		19.2		7.9		6.8		16.8
Total Electric Operating Revenues	$	127.9	$	113.6	12.6		$	497.2	$	440.4	12.9
Water Revenues	0.4		0.4		(1.6	)	1.8		1.8		1.4
Total Electric Segment Operating Revenues	$	128.3	$	114.0	12.6		$	499.0	$	442.2	12.9

*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 March 31 (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				Twelve Months Ended
	2011		2010		2011		2010
Electric revenues	$	127.9	$	113.6	$	497.2	$	440.4
Fuel and purchased power	54.2		50.7		202.8		185.9
Electric gross margins	$	73.7	$	62.9	$	294.4	$	254.5

Electric gross margins increased during 2011 in both periods presented mainly due to the Missouri and Kansas 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.

32

Quarter Ended March 31, 2011 Compared to Quarter Ended March 31, 2010

On-System Operating Revenues and Kilowatt-Hour Sales

KWh sales for our on-system customers decreased during the first quarter of 2011 as compared to the first quarter of 2010 primarily due to mild weather in the first quarter of 2011. Revenues for our on-system customers increased approximately $12.3 million, or 11.6%. Rate changes, primarily the September 2010 Missouri rate increase and the July 2010 Kansas rate increase, contributed an estimated $15.6 million to revenues. Continued sales growth contributed an estimated $0.5 million. Our electric customer growth for the twelve months ended March 31, 2011 was 0.1%. Weather and other related factors decreased revenues an estimated $3.8 million. Total heating degree days (the sum of the number of degrees that the daily average temperature for each day during that period was below 65° F) for the first quarter of 2011 were 6.8% less than the same period last year but 4.0% more than the 30-year average.

During the first quarter of 2011, the decrease in residential and commercial kWh sales was primarily due to the milder weather in the first quarter of 2011. The increase in residential and commercial revenues was primarily due to the Missouri and Kansas rate increases as well as continued sales growth.

Industrial kWh sales and revenues increased in the first quarter of 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 and Kansas rate increases.

On-system wholesale kWh sales increased 3.1% while revenues decreased 14.2% during the first quarter of 2011 as compared to the same period in 2010 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 working to finalize the terms of the settlement reached on September 15, 2010, with the FERC on our GFR tariffs.

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.

Off-system revenues and related expenses were higher during the first quarter of 2011 as compared to the first quarter of 2010 primarily due to increased demand. Total purchased power related expenses are included in our discussion of purchased power costs below.

Miscellaneous Revenues

Our miscellaneous revenues were $2.1 million during the first quarter of 2011 as compared to $1.8 million during the first 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 first quarter of 2011, total fuel and purchased power expenses increased approximately $3.5 million (7.0%) 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 first quarter of 2011 and 2010.

33

(in millions)	2011			2010
Actual fuel and purchased power expenditures	$	50.3		$	53.1
Kansas regulatory adjustments**	0.1			(0.4		)
Missouri fuel adjustment deferral**	1.1			(1.8		)
Missouri fuel adjustment recovery*	2.9			(0.5		)
Unrealized (gain)/loss on derivatives	(0.2		)	0.3
Total fuel and purchased power expense per income statement	$	54.2		$	50.7

* 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.

The overall fuel and purchased power increase primarily reflects additional recoveries of previously deferred fuel costs.

Summarized in the table below are our estimated cost and volume changes in the components of fuel and purchased power expenses for the first quarter of 2011 as compared to the first quarter of 2010. This table incorporates all the changes mentioned above. The largest impact on fuel and purchased power costs was increased generation by our coal-fired units.

	Three Months Ended
(in millions)	March 31, 2011 vs. 2010
Coal generation volume	$	4.4
Natural gas generation volume	(2.6		)
Purchased power spot purchase volume	(3.0		)
Coal (cost per mWh)	1.1
Natural gas (cost per mWh)	(2.5		)
Purchased power (cost per mWh)	0.2
Other (including fuel adjustments and related recoveries)	5.9
TOTAL	$	3.5

Operating Revenue Deductions — Other Than Fuel and Purchased Power

Regulated operating expenses increased approximately $1.4 million (8.7%) during the first 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 and distribution expense*	$	1.0
General labor costs	0.2
Employee pension expense	0.6
Customer accounts expense**	(0.2		)
Steam power other operating expense	0.8
Other steam power expense***	(1.0		)
TOTAL	$	1.4

*  Approximately $0.5 million of this total is for charges incurred for delivering the output from Plum Point to our system.

** Mainly decreased banking fees and uncollectible accounts.

***Related to Iatan 1 and Iatan 2 construction accounting in accordance with our agreement with the MPSC that allows deferral of certain costs until the plant additions are included in customer rates.

Maintenance and repairs expense increased approximately $1.4 million (18.9%) in the first quarter of 2011 as compared to the first quarter of 2010 primarily due to changes in the following accounts:

34

(in millions)	2011 vs. 2010
Distribution maintenance costs	$	0.7
Maintenance and repairs expense at the Iatan plant	0.4
Maintenance and repairs expense to the SLCC	0.4
Maintenance and repairs expense at the Plum Point plant	0.3
Maintenance and repairs expense to the Energy Center	0.1
Maintenance and repairs expense at the Asbury plant	(0.1		)
Maintenance and repairs expense to the Riverton coal units	(0.4		)
TOTAL	$	1.4

Depreciation and amortization expense increased approximately $3.7 million (30.3%) during the quarter. This reflects additional regulatory amortization of $2.5 million granted in our Missouri rate case effective September 10, 2010. The remainder is increased plant in service in the first 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 first quarter of 2011 was $0.8 million as compared to $0.3 million of Iatan 1 depreciation expense deferred in the first quarter of 2010.

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

Twelve Months Ended March 31, 2011 Compared to Twelve Months Ended March 31, 2010

On-System Operating Revenues and Kilowatt-Hour Sales

For the twelve months ended March 31, 2011, kWh sales to our on-system customers increased 3.1% with the associated revenues increasing approximately $47.7 million (11.4%). Rate changes, primarily the September 2010 Missouri rate increase and the July 2010 Kansas rate increase, contributed an estimated $32.9 million to revenues, while continued sales growth contributed an estimated $1.0 million. Weather and other related factors increased revenues an estimated $13.8 million. The increase in residential and commercial kWh sales during the twelve months ended March 31, 2011 was primarily due to favorable weather, while the increase in revenues reflect the positive weather as well as the Missouri and Kansas rate increases and continued sales growth. Industrial kWh sales increased during the twelve months ended March 31, 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 and Kansas rate increases. On-system wholesale kWh sales increased during the twelve months ended March 31, 2011 reflecting increased market demand resulting from the favorable weather.

Off-System Electric Transactions

Off-system revenues increased during the twelve months ended March 31, 2011 as compared to the same period in 2010 primarily due to increased market demand resulting from the favorable weather discussed above, but as discussed previously, margins are flowed back to customers. Total purchased power related expenses are included in our discussion of purchased power costs below.

Miscellaneous Revenues

Our miscellaneous revenues for the twelve months ended March 31, 2011 were $7.9 million as compared to $6.8 million in the same period of 2010. These revenues are comprised mainly of transmission revenues, late payment fees and renewable energy credit sales.

35

Operating Revenue Deductions — Fuel and Purchased Power

During the twelve months ended March 31, 2011, total fuel and purchased power expenses increased approximately $16.9 million (9.1%) during the twelve months ended March 31, 2011. 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 March 31, 2011.

(in millions)	2011			2010
Actual fuel and purchased power expenditures	$	197.2		$	185.6
Kansas regulatory adjustments**	0.3			(0.2		)
Missouri fuel adjustment deferral**	(1.6		)	(0.7		)
Missouri fuel adjustment recovery*	6.5			1.2
Unrealized (gain)/loss on derivatives	0.4			—
Total fuel and purchased power expense per income statement	$	202.8		$	185.9

*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.

The overall fuel and purchased power increase during the twelve months ended March 31, 2011 primarily reflects increased generation by both our coal-fired and gas-fired units due to increased market demand resulting from favorable weather conditions, as well as additional recoveries of previously deferred fuel costs.

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 March 31, 2011 as compared to the twelve months ended March 31, 2010. This table incorporates all the changes mentioned above. As shown below, the largest impact on fuel and purchased power costs was increased generation by our gas-fired units.

	Twelve Months Ended
(in millions)	March 31, 2011 vs 2010
Coal generation volume	$	9.8
Natural gas generation volume	24.0
Purchased power spot purchase volume	(10.4		)
Natural gas (cost per mWh)	(14.4		)
Coal (cost per mWh)	0.4
Purchased power (cost per mWh)	3.1
Other (including fuel adjustments and related recoveries)	4.4
TOTAL	$	16.9

Operating Revenue Deductions — Other Than Fuel and Purchased Power

Regulated operating expenses increased approximately $6.8 million (10.5%) during the twelve months ended March 31, 2011 as compared to the same period in 2010, primarily due to changes in the following accounts:

36

(in millions)	2011 vs. 2010
Transmission and distribution expense*	$	2.7
General labor costs	1.1
Employee pension expense	1.6
Employee health care expense	0.8
Customer accounts expense**	1.0
Steam power other operating expense	1.4
Property insurance	0.3
Injuries and damages expense	0.2
Customer assistance expense	0.3
Other power supply expense	0.3
Director, stockholder and other investor expense	0.2
General office expense	0.2
Other steam power expense***	(2.6		)
Professional services	(0.5		)
Other miscellaneous accounts (netted)	(0.2		)
TOTAL	$	6.8

*Approximately $2.1 million of this total is for charges incurred for delivering the output from Plum Point to our system.

**Mainly increased uncollectible accounts and banking fees.

***Related to Iatan 1 and Iatan 2 operating costs that we were able to defer in accordance with our agreement with the MPSC that allows deferral of certain costs until the plant additions are included in customer rates.

Maintenance and repairs expense increased approximately $5.2 million (16.0%) during the twelve months ended March 31, 2011 as compared to the twelve months ended March 31, 2010 primarily due to changes in the following accounts:

(in millions)	2011 vs. 2010
Distribution maintenance costs*	$	1.9
Maintenance and repairs expense at the Iatan plant	1.1
Maintenance and repairs expense at the Plum Point plant	0.7
Transmission expense	0.4
Maintenance and repairs expense to the Riverton gas units**	0.4
Maintenance and repairs expense to the SLCC	0.2
Maintenance and repairs expense at the Energy Center plant	0.2
Maintenance and repairs expense to the Riverton coal units	0.1
Other miscellaneous accounts (netted)	0.2
TOTAL	$	5.2

* Mainly due to continued implementation of our system reliability plan.

**Mainly due to 2010 fourth quarter maintenance outage on Unit No. 12.

Depreciation and amortization expense increased approximately $9.2 million (19.0%) during the twelve months ended March 31, 2011. This reflects additional regulatory amortization of $5.6 million granted in our Missouri rate case effective September 10, 2010. The remainder is increased plant in service, 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 $1.9 million as compared to $1.1 million of Iatan 1 depreciation expense in the prior period.

Other taxes increased approximately $2.6 million during the twelve months ended March 31, 2011 due to increased property tax reflecting our additions to plant in service and increased municipal franchise taxes.

37

Gas Segment

Gas Operating Revenues and Sales

The following tables detail our natural gas sales and revenues for the periods ended March 31:

Total Gas Delivered to Customers

	Three Months Ended				Twelve Months Ended
(bcf sales)	2011	2010	% change		2011	2010	% change
Residential	1.40	1.51	(7.6	)%	2.56	2.89	(11.4	)%
Commercial	0.63	0.65	(3.9	)	1.24	1.36	(9.1	)
Industrial*	0.05	0.05	1.9		0.11	0.11	0.3
Other**	0.02	0.02	(5.4	)	0.03	0.04	(10.0	)
Total retail sales	2.10	2.23	(6.3	)	3.94	4.40	(10.4	)
Transportation sales*	1.48	1.61	(7.5	)	4.71	4.77	(1.4	)
Total gas operating sales	3.58	3.84	(6.8	)	8.65	9.17	(5.7	)

Operating Revenues and Cost of Gas Sold

	Three Months Ended						Twelve Months Ended
($ in millions)	2011		2010		% change		2011		2010		% change
Residential	$	13.5	$	16.3	(16.8	)%	$	29.5	$	34.3	(14.1	)%
Commercial	5.7		6.6		(12.4	)	12.5		14.7		(14.8	)
Industrial*	0.3		0.3		(14.4	)	0.8		1.0		(23.4	)
Other**	0.2		0.2		(13.4	)	0.3		0.4		(16.7
Total retail revenues	$	19.7	$	23.4	(15.5	)	$	43.1	$	50.4	(14.5	)
Other revenues	0.1		0.1		72.8		0.5		0.2		150.7
Transportation revenues*	1.2		1.1		1.8		3.7		3.2		17.8
Total gas operating revenues	$	21.0	$	24.6	(14.5	)	$	47.3	$	53.8	(12.0	)
Cost of gas sold	12.0		15.1		(20.3	)	23.5		31.4		(25.0	)
Gas operating revenues over cost of gas in rates (margin)	$	9.0	$	9.5	(5.3	)	$	23.8	$	22.4	6.2

*Percentage change reflects a customer switching from industrial sales to transportation in October 2009 after an eight-month suspension.

**Other includes other public authorities and interdepartmental usage.

Quarter Ended March 31, 2011 Compared to Quarter Ended March 31, 2010

Operating Revenues and bcf Sales

Gas retail sales decreased 6.3% during the first quarter of 2011 as compared to 2010 reflecting customer contraction of 0.6%. Residential sales decreased 7.6% and commercial sales decreased 3.9% during the first quarter of 2011 as compared to the first quarter of 2010 reflecting the customer contraction. Although heating degree days were 0.8% more in the first quarter of 2011 as compared to the first quarter of 2010 and 7.8% more than the 30-year average, an extreme cold spell during the first quarter of 2010 caused an increase in sales during that period. Industrial sales increased 1.9% during the first quarter of 2011 as compared to the same period in 2010.

During the first quarter of 2011, gas segment revenues were approximately $21.0 million as compared to $24.6 million in the first quarter of 2010, a decrease of 14.5%. During the first quarter of 2011, our PGA revenue (which represents the cost of gas recovered from our customers) was approximately $12.0 million as compared to $15.1 million in the first quarter of 2010, a decrease of approximately $3.1 million. This decrease was largely driven by the lower gas prices reflected in the PGAs that became effective November 13, 2009 and November 2, 2010. Our margin for the first quarter of 2011 decreased $0.5 million as compared to the first quarter of 2010 due to the decrease 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 March 31, 2011, we had no unrecovered purchased

38

gas costs recorded as a regulatory asset and over recovered purchased gas costs of $2.6 million recorded as a regulatory liability.

Operating Revenue Deductions

Total other operating expenses were $2.1 million during the first quarter of 2011 as compared to $2.7 million in the first quarter of 2010, primarily due to a $0.3 million decrease in customer accounts expense (mainly uncollectible accounts) and a $0.2 million decrease in employee pension expense.

Our gas segment had net income of $2.2 million for the first quarter of 2011 as compared to $2.3 million for the first quarter of 2010.

Twelve Months Ended March 31, 2011 Compared to Twelve Months Ended March 31, 2010

Operating Revenues and bcf Sales

Gas retail sales decreased 10.4% during the twelve months ended March 31, 2011 reflecting customer contraction of 0.6%. We believe this contraction was due to depressed economic conditions. We estimate that the rate of gas customer contraction will level out during the next two years and begin modest growth after 2012. Residential and commercial sales decreased during the twelve months ended March 31, 2011 reflecting the customer contraction while industrial sales increased.

During the twelve months ended March 31, 2011, gas segment revenues were approximately $47.3 million as compared to $53.8 million in the twelve months ended March 31, 2010, a decrease of $6.5 million (12.0%). $5.0 million of this decrease was largely driven by the lower gas prices reflected in the PGAs that became effective November 13, 2009 and November 2, 2010. During the twelve months ended March 31, 2011, our PGA revenue was approximately $23.5 million as compared to $31.4 million during the twelve months ended March 31, 2010, a decrease of approximately $7.9 million. Our margin for the twelve months ended March 31, 2011 increased $1.4 million as compared to the same period in 2010.

Operating Revenue Deductions

Total other operating expenses were $8.9 million for the twelve months ended March 31, 2011 as compared to $10.1 million for the twelve months ended March 31, 2010. This decrease was mainly due to a $0.9 million decrease in employee pension expense, a $0.3 million decrease in customer accounts expense (mainly uncollectible accounts) and a $0.1 million decrease in customer assistance expense.

Our gas segment had net income of $2.5 million for the twelve months ended March 31, 2011 as compared to $1.4 million for the twelve months ended March 31, 2010.

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 March 31, 2011:

	Three Months Ended						Twelve Months Ended
	2011			2010			2011			2010
Consolidated provision for income taxes	$	7.3		$	9.9		$	27.8		$	24.2
Consolidated effective federal and state income tax rates	37.8		%	53.6		%	35.4		%	38.3		%

The effective tax rates for the first quarter of 2011 and the twelve months ended March 31, 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

39

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 is enacted. As a result, in the first quarter of 2010, we recorded a one-time non-cash charge of approximately $2.1 million to income taxes to reflect the impact of this change, 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 have 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 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. Amortization of the remaining regulatory tax asset will begin in 2011 or 2012, which is also when we expect to be able to request rate recovery of the asset.

We received $26.6 million in 2010 from the Southwest Power Administration (SWPA) which has been deferred for book purposes and treated as a noncurrent liability and is more fully described in our recent 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 filed a request 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 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 March 31, 2011.

Nonoperating Items

The following table shows the total allowance for funds used during construction (AFUDC) for the applicable periods ended March 31. AFUDC decreased during both the first quarter of 2011 and the twelve months ended March 31, 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				Twelve Months Ended
($ in millions)	2011		2010		2011		2010
Allowance for equity funds used during construction	$	—	$	1.8	$	2.8	$	6.6
Allowance for borrowed funds used during construction	—		2.4		3.2		8.1
Total AFUDC	$	—	$	4.2	$	6.0	$	14.7

Total interest charges on long-term and short-term debt for the periods ended March 31, 2011 are shown below. The decreases in long-term debt interest for both periods 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 primarily reflect lower levels of borrowing.

40

Interest Charges

($ in millions)

	3 Months			3 Months					12 Months			12 Months
	Ended			Ended			%		Ended			Ended			%
	2011			2010			Change		2011			2010			Change
Long-term debt interest	$	10.6		$	10.5		1.4	%	$	42.1		$	42.9		(1.9	)%
Short-term debt interest	—			0.2			(87.4	)	0.4			0.8			(47.2	)
Trust preferred securities interest	—			1.1			(100.0	)	1.0			4.3			(75.8	)
Iatan 1 and 2 carrying charges*	(1.1		)	(0.6		)	97.6		(3.7		)	(1.9		)	94.4
Other interest	0.2			0.2			(4.4	)	0.8			0.7			13.8
Total interest charges	$	9.7		$	11.4		(15.0	)	$	40.6		$	46.8		(13.1	)

*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. See Note 3 and Rate Matters below for additional information regarding carrying charges.

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 water rate increases since January 1, 2008:

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

Electric Segment

Missouri

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 the 2009 Missouri rate case (see below).

41

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.

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 will use construction accounting for our Iatan 2 project. (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,

42

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.

Kansas

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

Oklahoma

On March 25, 2010, we requested a capital cost recovery rider (CCRR) at the 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. The CRR revenue being collected is subject to refund/true-up in the next general rate case. We will file a general rate case within six months of the commercial operation date of Iatan 2 (which was December 31, 2010) to replace the CRR with permanent rates.

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 settlement calls for the implementation of a new tariff, the Transmission Cost Recovery Rider (TCR) designed to track changes in the cost of transmission charges from the Southwest Power Pool, Inc. and flow through off-system sales margins. The existing Energy Cost Recovery Rider was also modified to include the recovery of the costs associated with certain air quality control materials. The APSC approved the settlement on April 12, 2011 with the new rates to become effective with customer bills rendered after that date.

43

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 March 31, 2011, we had collected $1.0 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 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 are now working to finalize the terms of the 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. Based on the May 21, 2009 order, it is possible that the FERC will revoke our waiver which would impact communication between our transmission and wholesale marketing and sales functions and operations within our organization. As part of our filing, we sought a twelve month extension in order to comply with the Standard of Conduct requirements in the event the FERC determined that revoking our waiver was appropriate. 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 do not anticipate 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 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

44

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 debt redemptions, interest payments on debt obligations, dividend payments and other cash needs through the next several years.

We will continue to evaluate our need to increase available liquidity based on our view of working capital requirements, including the timing of our construction programs and other factors. 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 March 31:

Summary of Cash Flows

	Quarter Ended March 31,
(in millions)	2011			2010			Change
Cash provided by/(used in):
Operating activities	$	34.0		$	36.8		$	(2.8	)
Investing activities	(17.2		)	(34.8		)	17.6
Financing activities	(23.5		)	(1.7		)	(21.8		)
Net change in cash and cash equivalents	$	(6.7	)	$	0.3		$	7.0

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 change in natural gas prices directly impacts the cost of gas stored in inventory.

First Quarter 2011 Compared to 2010.  During the first quarter of 2011, our net cash flow provided from operating activities was $34.0 million, a decrease of $2.8 million or 7.6% from 2010. This change resulted from the following:

·Changes in net income - $3.3 million.

·Changes in depreciation and amortization, reflecting increased regulatory amortization, plant in service and fuel deferral amortization - $7.9 million

·Changes in pension and other post retirement benefit costs primarily due to the result of a $13.5 million pension contribution in the first quarter of 2011 — $(13.4) million.

·Decreased cash payments for income taxes, reflecting positive impacts for accelerated tax depreciation - $4.3 million.

·Changes in receivables due to higher insurance receipts in 2010 for a generator failure, seasonal levels of trade accounts receivable and unbilled revenues offset by reduced income taxes receivable - $(2.3) million.

·Changes in the levels of accounts payable primarily due to changes in unpresented checks for property tax payments - $3.4 million.

·Changes in interest and taxes due to lower accruals of income, property and corporate franchise taxes- $(6.6) million.

45

Capital Requirements and Investing Activities

Our net cash flows used in investing activities decreased $17.6 million during the first quarter of 2011 as compared to the first quarter of 2010.

Our capital expenditures incurred totaled approximately $17.5 million during the first quarter of 2011 compared to $30.9 million in the first quarter of 2010. The decrease was primarily the result of a decrease in new generation electric plant additions and replacements.

A breakdown of the capital expenditures for the quarters ended March 31, 2011 and 2010 is as follows:

	Capital Expenditures
(in millions)	2011			2010
Distribution and transmission system additions	$	10.9		$	7.4
New Generation — Plum Point Energy Station	(0.2		)	3.5
New Generation — Iatan 2	1.9			19.0
Additions and replacements — electric plant	1.8			0.3
Gas segment additions and replacements	0.2			0.2
Transportation	0.4			0.2
Other (including retirements and salvage - net) (1)	2.1			(1.1		)
Subtotal	17.1			29.5
Non-regulated capital expenditures (primarily fiber optics)	0.4			1.4
Subtotal capital expenditures incurred (2)	17.5			30.9
Adjusted for capital expenditures payable (3)	(0.3		)	3.9
Total cash outlay	$	17.2		$	34.8

(1)  Other includes no equity AFUDC for 2011 and $(1.8) million for 2010.

(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.

100% of our cash requirements for capital expenditures during the first quarter of 2011 were satisfied internally from operations (funds provided by operating activities less dividends paid).

We estimate that internally generated funds will provide approximately 93% 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 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 used in financing activities increased $21.8 million in the first quarter of 2011 as compared to 2010. In 2010, we received $32.6 million of new financing, primarily from the issuance of our stock equity plan. We used the 2010 stock issuance to fund dividends and pay down short-term debt, as well as fund our capital expenditures.

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 revolving credit facility. This agreement extends the termination date of the revolving credit facility from July 15, 2010 to January 26, 2013.

46

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 March 31, 2011, we are in compliance with these ratios. Our total indebtedness is 51.6% of our total capitalization as of March 31, 2011 and our EBITDA is 5.1 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 March 31, 2011. However, $11.0 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 March 31, 2011 would permit us to issue approximately $408.0 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 March 31, 2011, we had retired bonds and net property additions which would enable the issuance of at least $632.5 million principal amount of bonds if the annual interest requirements are met. As of March 31, 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 March 31, 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

47

revised their rating outlook on us to stable. On March 24, 2011, Fitch revised our commercial paper 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 March 31, 2011, compared to December 31, 2010.

DIVIDENDS

Holders of our common stock are entitled to dividends if, as, and when declared by the Board of Directors, out of funds legally available therefore, subject to the prior rights of holders of any outstanding cumulative preferred stock and preference stock. Payment of dividends is determined by our Board of Directors after considering all relevant factors, including the amount of our retained earnings (which is essentially our accumulated net income less dividend payouts). As of March 31, 2011, our retained earnings balance was $4.1 million, compared to $6.3 million as of March 31, 2010 and $5.5 million as of December 31, 2010, after paying out $13.3 million in dividends during the first quarter of 2011. A reduction of our dividend per share, partially or in whole, could have an adverse effect on our common stock price. On April 28, 2011, the Board of Directors declared a quarterly dividend of $0.32 per share on common stock payable June 15, 2011 to holders of record as of June 1, 2011.

Our diluted earnings per share were $0.29 for the quarter ended March 31, 2011 and were $1.17 and $1.18 for the years ended December 31, 2010 and 2009, respectively. Dividends paid per share were $0.32 for the three months ended March 31, 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. As of March 31, 2011, this restriction did not prevent us from issuing dividends.

48

OFF-BALANCE SHEET ARRANGEMENTS

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

CRITICAL ACCOUNTING POLICIES

See “Item 7 — Managements Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report 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 March 31, 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 2013. These contracts satisfy approximately 100% of 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

49

lessen the volatility in our fuel expenditures and improve predictability. As of April 22, 2011, 84%, or 4.3 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 March 31, 2011, our natural gas cost would increase by approximately $0.7 million based on our March 31, 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 March 31, 2011, we have 0.1 million Dths in storage on the three pipelines that serve our customers. This represents 4.3% 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 March 31, 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	Actual % Hedged
Current	50%	480,000	246,000	11	%
Second	Up to 50%	310,000	0	5	%
Third	Up to 20%	0	0	0	%
Total		790,000	246,000

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

(in millions)	March 31, 2011		December 31, 2010
Margin deposit assets	$	3.9	$	3.9

Our exposure to credit risk is concentrated primarily within our fuel procurement process, as we transact with a smaller, less diverse group of counterparties and transactions may involve large notional volumes and potentially volatile commodity prices. Below is a table showing our net credit exposure at March 31, 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.

50

(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	3.2
Net credit exposure	$	15.5

The $3.2 million net unrealized mark-to-market loss for financial natural gas contracts is comprised of $3.7 million that our counterparties are exposed to Empire for unrealized losses and $0.5 million of exposure to Empire of unrealized gains from 2 counterparties. We are holding no collateral from any counterparty since we are below the $10 million mark-to-market collateral threshold in our agreements. As noted above, as of March 31, 2011, we have $3.9 million on deposit for NYMEX contract exposure to Empire, of which $3.3 million represents our collateral requirement. In addition, if NYMEX gas prices decreased 25% from their March 31, 2011 levels, we would be required to post an additional $1.8 million in collateral. If these prices increased 25%, our collateral requirement would decrease $2.5 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 March 31, 2011.

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

51

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 March 31, 2011, our ratio of earnings to fixed charges was 2.70x.  See Exhibit (12) hereto.

Item 6.  Exhibits.

(a)	Exhibits.
	(12) Computation of Ratio of Earnings to Fixed Charges.
	(31)(a) Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
	(31)(b) Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
	(32)(a) Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.*
	(32)(b) Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.*
	(101) The following financial information from The Empire District Electric Company’s Quarterly Report on Form10-Q for the period ended March 31, 2011, filed with the SEC on May 9, 2011, formatted in Extensible Business Reporting Language (XBRL): (i) the Consolidated Statements of Income for the three and twelve month periods ended March 31, 2011 and 2010, (ii) the Consolidated Balance Sheets at March 31, 2011 and December 31, 2010, (iii) the Consolidated Statements of Cash Flows for the three-month periods ended March 31, 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” for purposes of Section 18 of the Exchange Act, or otherwise subject to the liability of that section, and shall not be deemed incorporated by reference into, or part of a registration statement, prospectus or other document filed under the Securities Act of 1933, as amended or the Exchange Act of 1934, as amended except as shall be expressly set forth by specific reference in such filings.

52

SIGNATURES

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

	THE EMPIRE DISTRICT ELECTRIC COMPANY
		Registrant
	By	/s/ Gregory A. Knapp
		Gregory A. Knapp
		Vice President — Finance and Chief Financial Officer
	By	/s/ Laurie A. Delano
		Laurie A. Delano
		Controller, Assistant Secretary and Assistant Treasurer
May 9, 2011

53