10-Q

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)

x	Quarterly report pursuant to Section 13 or 15(d) of the Securities Exchange Act of  1934
For the quarterly period ended March 31, 2012
or
o	Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the transition period from                         to                         .

Commission file number: 1-3368

THE EMPIRE DISTRICT ELECTRIC COMPANY

(Exact name of registrant as specified in its charter)

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

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

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes 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 (Do not check if a smaller reporting company)	Smaller reporting company o

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

As of April 30, 2012, 42,158,156 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		31
	Executive Summary		31
	Results of Operations		33
	Rate Matters		39
	Competition		40
	Liquidity and Capital Resources		42
	Contractual Obligations		46
	Dividends		46
	Off-Balance Sheet Arrangements		47
	Critical Accounting Policies		47
	Recently Issued Accounting Standards		47
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		47
Item 4.	Controls and Procedures		49
Part II -	Other Information:
Item 1.	Legal Proceedings		50
Item 1A.	Risk Factors		50
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds — (none)
Item 3.	Defaults Upon Senior Securities - (none)
Item 4.	Mine Safety Disclosures - (none)
Item 5.	Other Information		50
Item 6.	Exhibits		50
	Signatures		52

2

FORWARD LOOKING STATEMENTS

Certain matters discussed in this quarterly report are “forward-looking statements” intended to qualify for the safe harbor from liability established by the Private Securities Litigation Reform Act of 1995. Such statements address or may address future plans, objectives, expectations and events or conditions concerning various matters such as capital expenditures, earnings, impacts from the 2011 tornado, pension and other costs, competition, litigation, our construction program, our generation plans, our financing plans, potential acquisitions, rate and other regulatory matters, liquidity and capital resources and accounting matters. Forward-looking statements may contain words like “anticipate”, “believe”, “expect”, “project”, “objective” or similar expressions to identify them as forward-looking statements. Factors that could cause actual results to differ materially from those currently anticipated in such statements include:

·weather, business and economic conditions, recovery and rebuilding efforts relating to the 2011 tornado and other factors which may impact sales volumes and customer growth;

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

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

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

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

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

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

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

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

·competition, including the SPP Energy Imbalance Services Market;

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

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

·changes in accounting requirements (including the potential consequences of being required to report in accordance with IFRS rather than U. S. GAAP);

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

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

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

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

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

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

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

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

·acts of terrorism, including, but not limited to, cyber-terrorism; 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,
	2012			2011
	(000’s except per share amounts)
Operating revenues:
Electric and water	$	119,726		$	128,360
Gas	15,683			20,989
Other	1,735			1,379
	137,144			150,728
Operating revenue deductions:
Fuel and purchased power	45,229			54,217
Cost of natural gas sold and transported	8,581			12,040
Regulated operating expenses	23,348			19,715
Other operating expenses	598			475
Maintenance and repairs	9,124			9,242
Depreciation and amortization	14,935			17,333
Provision for income taxes	6,084			7,269
Other taxes	8,435			8,589
	116,334			128,880
Operating income	20,810			21,848
Other income and (deductions):
Allowance for equity funds used during construction	50			—
Interest income	179			23
Benefit/(provision) for other income taxes	(115		)	24
Other - non-operating expense, net	(227		)	(285		)
	(113		)	(238		)
Interest charges:
Long-term debt	10,654			10,633
Short-term debt	30			31
Allowance for borrowed funds used during construction	(48		)	(23		)
Other	257			(953		)
	10,893			9,688
Net income	$	9,804		$	11,922
Weighted average number of common shares outstanding - basic	42,047			41,665
Weighted average number of common shares outstanding — diluted	42,075			41,707
Total earnings per weighted average share of common stock — basic and diluted	$	0.23		$	0.29
Dividends declared per share of common stock	$	0.25		$	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,
	2012			2011
	(000’s except per share amounts)
Operating revenues:
Electric and water	$	515,641		$	499,042
Gas	41,124			47,314
Other	6,521			5,754
	563,286			552,110
Operating revenue deductions:
Fuel and purchased power	191,268			202,831
Cost of natural gas sold and transported	19,302			23,545
Regulated operating expenses	89,075			80,090
Other operating expenses	2,221			1,937
Maintenance and repairs	40,923			38,206
Loss on plant disallowance	150			—
Depreciation and amortization	61,138			62,804
Provision for income taxes	32,886			27,850
Other taxes	30,426			28,582
	467,389			465,845
Operating income	95,897			86,265
Other income and (deductions):
Allowance for equity funds used during construction	343			2,797
Interest income	712			129
Benefit/(provision) for other income taxes	(366		)	6
Other - non-operating expense, net	(1,224		)	(1,077		)
	(535		)	1,855
Interest charges:
Long-term debt	42,603			42,107
Trust preferred securities	—			1,027
Short-term debt	85			417
Allowance for borrowed funds used during construction	(243		)	(3,245		)
Other	63			(2,918		)
	42,508			37,388
Net income	$	52,854		$	50,732
Weighted average number of common shares outstanding - basic	41,946			41,300
Weighted average number of common shares outstanding — diluted	41,968			41,324
Total earnings per weighted average share of common stock — basic and diluted	$	1.26		$	1.23
Dividends declared per share of common stock	$	0.57		$	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,
	2012		2011
	($-000’s)
Net income	$	9,804	$	11,922
Comprehensive income	$	9,804	$	11,922

	Twelve Months Ended
	March 31,
	2012		2011
	($-000’s)
Net income	$	52,854	$	50,732
Reclassification adjustments for loss included in net income or reclassified to regulatory asset or liability	—		5,814
Net change in fair market value of open derivative contracts for period	—		(361		)
Income taxes	—		(2,078		)
Comprehensive income	$	52,854	$	54,107

See accompanying Notes to Consolidated Financial Statements.

6

THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS (UNAUDITED)

	March 31, 2012		December 31, 2011
	($-000’s)
Assets
Plant and property, at original cost:
Electric and water	$	2,094,840	$	2,074,748
Natural gas	67,263		66,918
Other	35,584		34,984
Construction work in progress	36,891		24,141
	2,234,578		2,200,791
Accumulated depreciation and amortization	649,363		637,139
	1,585,215		1,563,652
Current assets:
Cash and cash equivalents	2,269		5,408
Restricted cash	4,357		4,357
Accounts receivable — trade, net of allowance of $1,505 and $1,138, respectively	41,677		42,296
Accrued unbilled revenues	10,978		20,326
Accounts receivable — other	19,441		16,269
Fuel, materials and supplies	62,193		62,239
Prepaid expenses and other	11,874		14,629
Regulatory assets	3,885		7,724
	156,674		173,248
Noncurrent assets and deferred charges:
Regulatory assets	231,428		231,922
Goodwill	39,492		39,492
Unamortized debt issuance costs	9,040		9,331
Other	4,610		4,190
	284,570		284,935
Total Assets	$	2,026,459	$	2,021,835

(Continued)

See accompanying Notes to Consolidated Financial Statements.

7

THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS (UNAUDITED) (Continued)

	March 31, 2012		December 31, 2011
	($-000’s)
Capitalization and Liabilities
Common stock, $1 par value, 42,114,630 and 41,977,725 shares issued and outstanding, respectively	$	42,115	$	41,978
Capital in excess of par value	621,306		618,304
Retained earnings	32,997		33,707
Total common stockholders’ equity	696,418		693,989
Long-term debt (net of current portion):
Obligations under capital lease	4,666		4,739
First mortgage bonds and secured debt	399,764		487,948
Unsecured debt	199,590		199,572
Total long-term debt	604,020		692,259
Total long-term debt and common stockholders’ equity	1,300,438		1,386,248
Current liabilities:
Accounts payable and accrued liabilities	43,605		59,307
Current maturities of long-term debt	75,773		933
Short-term debt	22,500		12,000
Customer deposits	11,671		11,428
Interest accrued	12,022		5,958
Unrealized loss in fair value of derivative contracts	6,171		4,769
Taxes accrued	7,177		2,634
	178,919		97,029
Commitments and contingencies (Note 7)
Noncurrent liabilities and deferred credits:
Regulatory liabilities	131,667		128,440
Deferred income taxes	268,577		263,933
Unamortized investment tax credits	19,165		19,226
Pension and other postretirement benefit obligations	102,071		103,371
Unrealized loss in fair value of derivative contracts	6,028		5,081
Other	19,594		18,507
	547,102		538,558
Total Capitalization and Liabilities	$	2,026,459	$	2,021,835

See accompanying Notes to Consolidated Financial Statements.

8

THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

	Three Months Ended
	March 31,
	2012			2011
	($-000’s)
Operating activities:
Net income	$	9,804		$	11,922
Adjustments to reconcile net income to cash flows from operating activities:
Depreciation and amortization including regulatory items	20,846			22,796
Pension and other postretirement benefit costs, net of contributions	1,035			(11,768		)
Deferred income taxes and unamortized investment tax credit, net	6,495			8,537
Allowance for equity funds used during construction	(50		)	—
Stock compensation expense	871			867
Cash flows impacted by changes in:
Accounts receivable and accrued unbilled revenues	6,795			6,052
Fuel, materials and supplies	46			1,001
Prepaid expenses, other current assets and deferred charges	(1,281		)	(4,070		)
Accounts payable and accrued liabilities	(18,254		)	(15,066		)
Interest, taxes accrued and customer deposits	10,850			9,556
Accumulated provision — rate refunds	—			375
Other liabilities and other deferred credits	1,970			3,829
Net cash provided by operating activities	39,127			34,031
Investing activities:
Capital expenditures — regulated	(30,355		)	(16,957		)
Capital expenditures and other investments — non-regulated	(699		)	(292		)
Net cash used in investing activities	(31,054		)	(17,249		)
Financing activities:
Proceeds from issuance of common stock, net of issuance costs	2,230			3,073
Net short-term borrowings/(repayments)	10,500			(13,000		)
Repayment of first mortgage bonds	(13,200		)	—
Dividends	(10,514		)	(13,337		)
Other	(228		)	(212		)
Net cash used in financing activities	(11,212		)	(23,476		)
Net decrease in cash and cash equivalents	(3,139		)	(6,694		)
Cash and cash equivalents at beginning of period	5,408			14,499
Cash and cash equivalents at end of period	$	2,269		$	7,805

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, 2011.

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, 2011, of which there were none.

Note 2 - Recently Issued and Proposed Accounting Standards

Balance Sheet Offsetting:  In December 2011, the FASB amended the guidance governing the offsetting, or netting, of assets and liabilities on the balance sheet.  Under the revised guidance, an entity would be required to disclose both the gross and net information about instruments and transactions that are eligible for offset on the balance sheet, as well as instruments or transactions subject to a master netting agreement.  This standard is effective for annual periods beginning after January 1, 2013.  The application of this standard will not have a material impact on our results of operations, financial position or liquidity.

See Note 1 under “Notes to Consolidated Financial Statements” in our Annual Report on Form 10-K for the year ended December 31, 2011 for further information regarding recently issued and proposed accounting standards.

Note 3— Regulatory Matters

The Missouri Public Service Commission (MPSC) approved a joint settlement agreement allowing us to defer actual incremental operating and maintenance expenses associated with the repair, restoration and rebuilding activities resulting from the tornado which hit our service territory on May 22, 2011. In addition, depreciation related to the capital expenditures will be deferred and a carrying charge will be accrued. These amounts, which were approximately $2.0 million as of March 31, 2012, have been recorded as a regulatory asset.

As part of a stipulated agreement in our 2009 Kansas rate case, approved by the KCC on June 25, 2010, we also deferred depreciation and operating and maintenance expense on both Plum Point and Iatan 2 from their respective in-service dates until the effective date for rates from the next Kansas case, which was January 1, 2012. These deferrals will be recovered over a 4 year period.

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, 2012		December 31, 2011
Regulatory Assets:
Under recovered purchased gas costs — gas segment - current	$	224	$	211
Under recovered electric fuel and purchased power costs — current	3,661		7,513
Regulatory assets, current(1)	3,885		7,724
Pension and other postretirement benefits(2)	118,417		121,058
Income taxes	49,330		49,631
Deferred construction accounting costs(3)	17,087		17,095
Unamortized loss on reacquired debt	11,333		11,610
Unsettled derivative losses — electric segment	10,117		7,839
System reliability — vegetation management	7,218		6,569
Storm costs(4)	5,025		5,303
Asset retirement obligation	4,568		3,571
Customer programs	3,718		3,408
Unamortized loss on interest rate derivative	1,383		1,462
Other	696		1,420
Under recovered purchased gas costs — gas segment	627		1,281
Deferred operating and maintenance expense	1,676		1,444
Under recovered electric fuel and purchased power costs	233		231
Regulatory assets, long-term	231,428		231,922
Total Regulatory Assets	$	235,313	$	239,646

	March 31, 2012		December 31, 2011
Regulatory Liabilities:
Costs of removal	75,923		73,562
SWPA payment for Ozark Beach lost generation	24,418		25,074
Income taxes	12,270		12,337
Deferred construction accounting costs — fuel(3)	8,266		8,304
Unamortized gain on interest rate derivative	3,669		3,711
Pension and other postretirement benefits(5)	2,675		2,939
Over recovered electric fuel and purchased power costs	4,446		2,513
Other	—		—
Regulatory liabilities, long-term	131,667		128,440
Total Regulatory Liabilities	$	131,667	$	128,440

(1)  Reflects over and under recovered costs expected to be returned or recovered, as applicable, within the next 12 months in Missouri, Kansas and Oklahoma rates.

(2) Primarily reflects regulatory assets resulting from the unfunded portion of our pension and OPEB liabilities and regulatory accounting for EDG acquisition costs. Approximately $0.1 million in pension and other postretirement benefit costs have been recognized since January 1, 2012 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)  Reflects the deferral of depreciation, operations and maintenance and carrying costs relating to Iatan 1 and Iatan 2 in accordance with our 2005 regulatory plan, as well as Plum Point construction costs incurred subsequent to February 28, 2010. All of these deferrals ended when recovery in rates began and these costs are now being amortized over the life of the plants. The regulatory plan also required us to continue to defer the fuel and purchased power expense impacts of Iatan 2, which are recorded in Non-Current Regulatory Liabilities.

Balances as of March 31, 2012	Deferred Carrying Charges		Deferred O&M	Depreciation	Total
Iatan 1	$	2,715	1,358	1,645	$	5,718
Iatan 2	$	3,873	4,279	2,718	$	10,870
Plum Point	$	65	276	158	$	499
Total					$	17,087

Balances as of December 31, 2011	Deferred Carrying Charges		Deferred O&M	Depreciation	Total
Iatan 1	$	2,728	1,363	1,652	$	5,743
Iatan 2	$	3,891	4,271	2,728	$	10,890
Plum Point	$	65	239	158	$	462
Total					$	17,095

(4)  Reflects ice storm costs incurred in 2007 and costs incurred as a result of the May 2011 tornado.

11

(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, 2012, regulatory liabilities and corresponding expenses have been reduced by less than $0.1 million as a result of ratemaking treatment.

Note 4— Risk Management and Derivative Financial Instruments

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

All derivative instruments are recognized at fair value on the balance sheet with the unrealized losses or gains from derivatives used to hedge our fuel costs in our electric segment recorded in regulatory assets or liabilities. All gains and losses from derivatives related to the gas segment are also 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, 2012 and December 31, 2011, we have recorded the following assets and liabilities representing the fair value of derivative financial instruments, (in thousands):

		March 31,		December 31,
ASSET DERIVATIVES		2012		2011
Non-designated hedging instruments due to regulatory accounting	Balance Sheet Classification	Fair Value		Fair Value
	Non-current assets and deferred charges — Other	$	12	$	2
Total derivatives assets		$	12	$	2

LIABILITY DERIVATIVES
Non-designated as hedging instruments due to regulatory accounting		March 31, 2012		December 31, 2011
Natural gas contracts, gas segment	Current liabilities	$	1,097	$	967
	Non-current liabilities and deferred credits	3		86
Natural gas contracts, electric segment	Current liabilities	5,074		3,802
	Non-current liabilities and deferred credits	6,025		4,995
Total derivatives liabilities		$	12,199	$	9,850

Electric

At March 31, 2012, approximately $5.1 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 Classification of	Amount of Gain / (Loss) Reclassed from OCI into Income (Effective portion)
Derivatives in Cash Flow Hedging	Gain / (Loss) on	Three Months Ended				Twelve Months Ended
Relationships - Electric Segment	Derivative	2012		2011		2012		2011
Commodity contracts	Fuel and purchased power expense	$	—	$	—	$	—	$	(5,814	)
Total Effective - Electric Segment		$	—	$	—	$	—	$	(5,814	)

	Statement of	Amount of Gain / (Loss) Recognized in OCI on Derivative (Effective portion)
Derivatives in Cash Flow Hedging	Comprehensive	Three Months Ended				Twelve Months Ended
Relationships - Electric Segment	Income	2012		2011		2012		2011
Commodity contracts	Fuel and purchased power expense	$	—	$	—	$	—	$	(361	)
Total Effective - Electric Segment		$	—	$	—	$	—	$	(361	)

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, 2012 and 2011, respectively.

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):

Non-Designated Hedging Instruments	Balance Sheet	Amount of Gain / (Loss) Recognized on Balance Sheet
— Due to Regulatory Accounting	Classification of Gain /	Three Months Ended					Twelve Months Ended
Electric Segment	(Loss) on Derivative	2012			2011		2012			2011
Commodity contracts — electric segment	Regulatory (assets)/liabilities	$	(2,302	)	$	632	$	(9,899	)	$	(2,037	)
Total Electric Segment		$	(2,302	)	$	632	$	(9,899	)	$	(2,037	)

Non-Designated Hedging Instruments	Statement of Operations	Amount of Gain / (Loss) Recognized in Income on Derivative
— Due to Regulatory Accounting	Classification of Gain /	Three Months Ended					Twelve Months Ended
Electric Segment	(Loss) on Derivative	2012			2011		2012			2011
Commodity contracts	Fuel and purchased power expense	$	(24	)	$	160	$	(2,416	)	$	(592	)
Total Electric Segment		$	(24	)	$	160	$	(2,416	)	$	(592	)

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 March 31, 2012, the following volumes and percentage of our anticipated volume of natural gas usage for our electric operations for the remainder of 2012 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 2012	66	%	2,111,000	1,110,000	$	6.363
2013	44	%	2,020,000	1,440,000	$	6.079
2014	20	%	460,000	1,240,000	$	5.514
2015	11	%	—	1,010,000	$	5.439
2016	—		—	—	—

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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, 2012, we had 0.8 million Dths in storage on the three pipelines that serve our customers. This represents 37% 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, 2012 (in thousands).

Season	Minimum % Hedged	Dth Hedged — Financial	Dth Hedged — Physical	Dth in Storage	Actual % Hedged
Current	50%	780,000	81,770	756,565	48	%
Second	Up to 50%	100,000	—	—	2	%
Third	Up to 20%	—	—	—	—
Total		880,000	81,770	756,565

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).

Non-Designated Hedging	Balance Sheet Classification of	Amount of Gain / (Loss) Recognized on Balance Sheet
Instruments Due to Regulatory	Gain or (Loss) on	Three Months Ended						Twelve Months Ended
Accounting — Gas Segment	Derivative	2012			2011			2012			2011
Commodity contracts	Regulatory assets	$	(655	)	$	(96	)	$	(2,475	)	$	(595	)
Total - Gas Segment		$	(655	)	$	(96	)	$	(2,475	)	$	(595	)

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

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liability positions. The aggregate fair value of all derivative instruments with the credit-risk-related contingent features that are in a liability position on March 31, 2012 is $3.1 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, 2012, we would have been required to post $3.1 million of collateral with one of our counterparties. On March 31, 2012, 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, 2012 and December 31, 2011:

($ in 000’s)

	Fair Value Measurements at Reporting Date Using
Description	Assets/(Liabilities) at Fair Value			Quoted Prices in Active Markets for Identical Liabilities (Level 1)			Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
				March 31, 2012
Net derivative liabilities*	$	(12,187	)	$	(12,187	)	$	—	$	—
				December 31, 2011
Net derivative liabilities*	$	(9,848	)	$	(9,848	)	$	—	$	—

*The only recurring measurements are derivative related and assets and liabilities are netted together in the table above.

Long-Term Debt

The carrying amount of our total debt exclusive of capital leases at March 31, 2012, was $674.8 million compared to a fair market value of approximately $726.7 million. These estimates were based on a bond pricing model, utilizing inputs classified as Level 2 in the fair value hierarchy, which include 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, 2012 or that will be realizable in the future.

Note 6— Financing

On April 1, 2012, we redeemed all $74.8 million aggregate principal amount of our First Mortgage Bonds, 7.00% Series due 2024, which is classified as a current liability on the March 31, 2012 balance sheet. All $5.2 million of our First Mortgage Bonds, 5.20% Pollution Control Series due 2013, and all $8.0 million of our First Mortgage Bonds, 5.30% Pollution Control Series due 2013 were also redeemed with payment made to the trustee prior to March 31, 2012.

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On April 2, 2012, we entered into a Bond Purchase Agreement for a private placement of $88 million aggregate principal amount of 3.58% First Mortgage Bonds due April 2, 2027. The first settlement of $38 million occurred on April 2, 2012 and a second settlement of $50 million is anticipated to occur on or about June 1, 2012. The bonds will mature on April 2, 2027. Interest is payable semi-annually on the bonds on each April 2 and October 2, commencing October 2, 2012. The bonds may be redeemed, at our option, at any time prior to maturity, at par plus a make whole premium, together with accrued and unpaid interest, if any, to the redemption date. The bonds have not been registered under the Securities Act of 1933, as amended, and may not be offered or sold in the United States absent registration or an applicable exemption from registration requirements. We will use the proceeds from the sale of these bonds to redeem the called bonds discussed above (including to repay short term debt initially used for such purpose). The bonds have been and will be issued under the EDE mortgage. 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.

We have an unsecured revolving credit facility of $150 million in place through January 17, 2017. 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, 2012, we are in compliance with these ratios. Our total indebtedness is 50.2% of our total capitalization as of March 31, 2012 and our EBITDA is 4.8 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, 2012. However, $22.5 million was used to back up our outstanding commercial paper.

Note 7— Commitments and Contingencies

Legal Proceedings

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 crops due to inappropriate management of the levee system around the Iatan Generating Station, of which we are a 12% owner. This matter was set for trial beginning November 7, 2011, but has now been rescheduled for May 29, 2012. Settlement negotiations are ongoing. We are unable to predict the outcome of the law suit or estimate the amount of damages, if any.

A lawsuit has been filed in Jasper County Circuit Court against us by three of our residential customers, purporting to act on behalf of all Empire customers. These customers are seeking a refund of certain amounts paid for service provided by Empire between January 1, 2007, and December 13, 2007. We will vigorously defend against the claims made against us by these three residential customers. We filed a motion asking the court to dismiss the case on the basis that the plaintiffs have not stated a valid claim. A hearing on our motion was held April 18, 2012. At all times, we charged the three plaintiffs, and all of our customers, the rates approved by and on file with the MPSC from our 2006 rate case. The orders of the MPSC in that case were appealed by the OPC,

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acting on behalf of the public, and certain industrial customers. The Missouri Court of Appeals affirmed all decisions entered by the MPSC in our 2006 rate case.

Coal, Natural Gas and Transportation Contracts

(in millions)	Firm physical gas and transportation contracts		Coal and coal transportation contracts
April 1, 2012 through December 31, 2012	$	25.5	$	26.7
January 1, 2013 through December 31, 2014	45.7		46.3
January 1, 2015 through December 31, 2016	24.5		31.4
January 1, 2017 and beyond	17.8		—

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

We have entered into long and short-term agreements to purchase coal and natural gas for our energy supply and natural gas operations. Under these contracts, the natural gas supplies are divided into firm physical commitments and derivatives that are used to hedge future purchases. In the event that this gas cannot be used at our plants, the gas would be liquidated at market price or put in storage. 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 entities 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 near Osceola, Arkansas. We began receiving purchased power on September 1, 2010. Commitments under this contract total approximately $32.7 million through August 30, 2015. We have the option to purchase an undivided ownership interest in the 50 megawatts covered by the purchased power agreement in 2015.

We have a 20-year purchased power agreement, which began on December 15, 2008, with Cloud County Windfarm, LLC, owned by EDP Renewables North America LLC (formerly Horizon Wind Energy), Houston, Texas to purchase the energy generated at the approximately 105-megawatt Phase 1 Meridian Way Wind Farm located in Cloud County, Kansas. We also have a 20-year contract, which began on December 15, 2005, with Elk River Windfarm, LLC, owned by IBERDROLA RENEWABLES, Inc., to purchase the energy generated at the 150-megawatt Elk River Windfarm located in Butler County, Kansas. Although these agreements are considered operating leases under 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. We do not own any portion of these windfarms. See Note 11 under “Notes to Consolidated Financial Statements” in our Annual Report on Form 10-K for the year ended December 31, 2011 for further information.

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New Construction

On January 16, 2012, we signed a contract with a third party vendor to complete environmental retrofits at our Asbury plant. The retrofits will include the installation of a pulse-jet fabric filter (baghouse), circulating dry scrubber and powder activated carbon injection system. This equipment will enable us to comply with the recently finalized Mercury and Air Toxics Standard (MATS) as further described in the Environmental Matters below. In total, the costs for this project are estimated to range from $112 million to $130 million, excluding AFUDC. Initial construction costs through March 31, 2012 were $7.9 million for 2012 and $9.2 million for the project to date, excluding AFUDC.

Leases

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

We also currently have short-term operating leases for two unit trains to meet coal delivery demands, for garage and office facilities for our electric segment and for one office facility related to our gas segment. In addition, we have capital leases for certain office equipment and 108 railcars to provide coal delivery for our ownership and purchased power agreement shares of the Plum Point generating facility.

Environmental Matters

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

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, nitrogen oxides (NOx) and mercury. In the future they are also likely to include limits on 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.

Compliance Plan

In order to comply with forthcoming environmental regulations, Empire is taking actions to implement its compliance plan and strategy (Compliance Plan).  While the Cross State Air Pollution Rule (CSAPR) that was set to take effect on January 1, 2012 was stayed in late December 2011 by the District of Columbia Circuit Court of Appeals, the MATS Rules were signed by the Environmental Protection Agency (EPA) Administrator on December 16, 2011 and became effective on April 16, 2012. MATS will require compliance by April 2015 (with flexibility for extensions for reliability reasons).

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Our Compliance Plan largely follows the preferred plan presented in our most recent Integrated Resource Plan. Our Compliance Plan calls for the installation of a scrubber, fabric filter, and powder activated carbon injection system at our Asbury plant by early 2015 at a cost ranging from $112 million to $130 million, excluding AFUDC. Initial construction costs through March 31, 2012 were $7.9 million for 2012 and $9.2 million project to date, excluding AFUDC. The addition of this air quality control equipment will require the retirement of Asbury Unit 2, an 18 megawatt steam turbine that is currently used for peaking purposes. The Compliance Plan also calls for the transition of our Riverton Units 7 and 8 from operation on coal to full operation on natural gas after the summer of 2013.  Riverton Units 7 and 8, along with Riverton Unit 9, a small combustion turbine that requires steam from Unit 7 for start-up, will be retired upon the conversion of Riverton Unit 12, a recently installed simple cycle combustion turbine, to a combined cycle unit. This conversion is currently scheduled to be completed in 2016.

SO2 Emissions

The CAA regulates the amount of SO2 an affected unit can emit. Currently SO2 emissions are regulated by the Title IV Acid Rain Program and the Clean Air Interstate Rule (CAIR). On January 1, 2012, CAIR was to have been replaced by the Cross-State Air Pollution Rule (CSAPR- formerly the Clean Air Transport Rule). But, on December 30, 2011 the District of Columbia Circuit Court of Appeals issued a stay of the CSAPR.  In the meantime, while the case is reviewed, both the Title IV Acid Rain Program and CAIR will remain in effect.

The Mercury Air Toxics Standards (MATS), discussed further below, was signed on December 16, 2011, and will affect SO2 emission rates at our facilities. In addition, the compliance date for the revised SO2 National Ambient Air Quality Standards (NAAQS) is August of 2017; this will also affect SO2 emissions from our facilities. The SO2 NAAQS is discussed in more detail below.

Title IV Acid Rain Program:

Under the Title IV Acid Rain Program, each existing affected unit has been allocated a specific number of emission allowances by the U.S. Environmental Protection Agency (EPA).  Each allowance entitles the holder to emit one ton of SO2. Covered utilities, such as Empire, must have emission allowances equal to the number of tons of SO2 emitted during a given year by each of their affected units. Allowances in excess of the annual emissions are banked for future use. In 2010, our SO2 emissions exceeded the annual allocations. This deficit was covered by our banked allowances. When our Title IV Acid Rain Program SO2 allowance bank is exhausted, currently estimated to be mid to late 2013, we will need to purchase additional SO2 allowances, blend more low sulfur coal at our facilities or transition our coal-fired Riverton Units 7 and 8 to natural gas or a combination of the above. Long-term compliance with this program will be met by the Compliance Plan detailed above along with possible procurement of additional SO2 allowances. We expect the cost of compliance to be fully recoverable in our rates.

CAIR:

In 2005, the EPA promulgated CAIR under the CAA. CAIR generally calls for fossil-fueled power plants greater than 25 megawatts to reduce emission levels of SO2 and/or NOx in 28 eastern states and the District of Columbia, including Missouri, where our Asbury, Energy Center, State Line and Iatan Units No. 1 and No. 2 are located. Kansas was not included in CAIR and our Riverton Plant was not affected. Arkansas, where our Plum Point Plant is located, was included for ozone season NOx but not for SO2.

In 2008, the U.S. Court of Appeals for the District of Columbia vacated CAIR and remanded it back to EPA for further consideration, but also stayed its vacatur. As a result, CAIR became effective for NOx on January 1, 2009 and for SO2 on January 1, 2010 and required covered states to develop State Implementation Plans (SIPs) to comply with specific SO2 state-wide annual budgets.

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

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Missouri units. As a result, based on current SO2 allowance usage projections, we expected to have sufficient allowances to take us into the latter part of 2012.

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

CSAPR- formerly the Clean Air Transport Rule:

On July 6, 2010, the EPA published a proposed CAIR replacement rule entitled the Clean Air Transport Rule (CATR). As proposed and supplemented, the CATR included Missouri and Kansas under both the annual and ozone season for NOx as well as the SO2 program while Arkansas remained in the ozone season NOx program only. The final CATR was released on July 7, 2011 under the name of the CSAPR, and was set to become effective January 1, 2012. However, as mentioned above, the District of Columbia Circuit Court of Appeals stayed the rule and as of January 1, 2012, the CAIR will be in effect while the court reviews the case. When it was published, the final CSAPR required a 73% reduction in SO2 from 2005 levels by 2014. The SO2 allowances allocated under the EPA’s Title IV Acid Rain Program cannot be used for compliance with CSAPR but would continue to be used for compliance with the Title IV Acid Rain Program. Therefore, new SO2 allowances would be allocated under CSAPR and retired at one allowance per ton of SO2 emissions emitted. We would receive fewer SO2 allowances than we currently emit. Long-term compliance with this Rule will be met by the Compliance Plan detailed above along with possible procurement of additional SO2 allowances. A number of states, including Kansas, various electric utilities and industrial organizations commenced litigation in the District of Columbia Court of Appeals challenging the December 2011 stay of the CSAPR. A ruling in that litigation is expected some time in mid- to late- 2012. We expect compliance costs with the resulting rules to be recoverable in our rates.

Mercury Air Toxics Standard (MATS):

The MATS standard was fully implemented and effective as of April 16, 2012, thus requiring compliance by April 16, 2015 (with flexibility for extensions for reliability reasons). The MATS regulation does not include allowance mechanisms, instead, it establishes alternative standards for certain pollutants, including SO2 (as a surrogate for hydrogen chloride (HCI)), which must be met to show compliance with hazardous air pollutant limits (see additional discussion in the MATS section below).

SO2 National Ambient Air Quality Standard (NAAQS):

In June 2010, the EPA finalized a new 1-hour SO2 NAAQS which, for areas with no SO2 monitor, originally required modeling to determine attainment and non-attainment areas within each state, but in April 2012, the EPA announced that it is reconsidering this approach. The modeling of emission sources was to have been completed by June 2013 with compliance with the SO2 NAAQS required by August 2017. Because the EPA is reconsidering the compliance determination approach, the compliance time-frame may be pushed back. Draft guidance for 1-hour SO2 NAAQS has been published by the EPA to assist states as they prepare their SIP submissions. The EPA is also planning a rulemaking to address some of the 1-hour SO2 NAAQS implementation program elements. It is likely coal-fired generating units will need scrubbers to be capable of meeting the new 1-hour SO2 NAAQS. In addition, units will be required to include SO2 emissions limits in their Title V permits or execute consent decrees to assure attainment and future compliance.

NOx Emissions

The CAA regulates the amount of NOx an affected unit can emit. As currently operated, each of our affected units is in compliance with the applicable NOx limits. Currently, revised NOx emissions

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are limited by the CAIR (subject to the outcome of the CSAPR proceedings) and by ozone NAAQS rules (discussed below) which were established in 1997 and in 2008.

CAIR:

In 2005, the EPA promulgated CAIR under the CAA. CAIR generally calls for fossil-fueled power plants greater than 25 megawatts to reduce emission levels of NOx in 28 states, including Missouri, where our Asbury, Energy Center, State Line and Iatan Units No. 1 and No. 2 are located and Arkansas where the Plum Point Energy Station is located. Kansas was not included in CAIR and our Riverton Plant was not affected.

The CAIR required covered states to develop SIPs to comply with specific annual NOx state-wide allowance allocation budgets. Based on existing SIPs, we had excess NOx allowances during 2010 which were banked for future use and will be sufficient for compliance at least through the end of 2012. The CAIR NOx program also was to have been replaced by the CSAPR program January 1, 2012 but because of the court stay will remain in effect while the case is reviewed.

CSAPR:

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

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

Ozone NAAQS:

Ozone, also called ground level smog, is formed by the mixing of NOx and Volatile Organic Compounds (VOCs) in the presence of sunlight. On January 6, 2010, the EPA proposed to lower the primary NAAQS for ozone designed to protect public health to a range between 60 and 70 ppb and to set a separate secondary NAAQS for ozone designed to protect sensitive vegetation and ecosystems.

On September 2, 2011, President Obama ordered the EPA to withdraw proposed air quality standards lowering the 2008 ozone standard pending the CAA 2013 scheduled reconsideration of the ozone NAAQS (the normal 5 year reconsideration period). States will move forward with area designations based on the 2008 75 ppb standard using 2008-2010 quality assured monitoring data. Our service territory will be designated as attainment, meaning it will be in compliance with the standard. In the interim, the 1997 ozone NAAQS will remain in effect.

Mercury Air Toxics Standard (MATS)

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

The EPA issued an Information Collection Request (ICR) for determining the National Emission Standards for Hazardous Air Pollutants (NESHAP), including mercury, for coal and oil-fired electric steam generating units on December 24, 2009. This ICR included our Iatan, Asbury and Riverton plants. All ICRs were submitted as required. The EPA ICR was intended for use in developing regulations under Section 112(r) of the CAA maximum achievable emission standards for the control of the emission of hazardous air pollutants (HAPs), including mercury. The EPA proposed the first ever national mercury and air toxics standards (MATS) in March 2011. It was signed by the EPA Administrator on December 16, 2011, published in the Federal Register on February 16, 2012

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and fully implemented and effective as of April 16, 2012. MATS establishes numerical emission limits to reduce emissions of heavy metals, including mercury (Hg), arsenic, chromium, and nickel, and acid gases, including HCl and hydrogen fluoride (HF). For all existing and new coal-fired electric utility steam generating units (EGUs), the proposed standard will be phased in over three years, and allows states the ability to give facilities a fourth year to comply.

The MATS regulation of HAPs in combination with CSAPR is the driving regulation behind our Compliance Plan and its implementation schedule.  We expect compliance costs to be recoverable in our rates.

Greenhouse Gases

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

On September 22, 2009, the EPA issued the final Mandatory Reporting of Greenhouse Gases Rule under the CAA which requires power generating and certain other facilities that equal or exceed an emission threshold of 25,000 metric tons of CO2e to report GHGs to the EPA annually commencing in September 2011. GHG emissions for 2010 and 2011 have been reported as required to the EPA by EDE. Under a special provision for the 2011 reporting year, EDG will incur a reporting deadline extension as a facility that contains a new reporting source. On January 11, 2012 EPA released the greenhouse gas data reported from large facilities and suppliers across the U.S. economy for the year 2010.

On December 7, 2009, responding to a 2007 U.S. 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 did not itself trigger any EPA regulations, but was 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 required the EPA to propose New Source Performance Standards (NSPS) for GHGs for fossil-fuel fired steam generating units by September 30, 2011 and to issue final GHG NSPS standards by May 26, 2012.

On March 27, 2012, the EPA proposed a Carbon Pollution Standard for new power plants. This action is designed to limit the amount of carbon emitted by electric utility generating units.

The new source performance standards (NSPS) would require all new power plants to meet a CO2 emissions limit of 1,000 pounds per megawatt hour.  This is equal to a coal-fired power plant capturing 50% or more of its emissions. The rule does offer some flexibility but would still require an average of 1,000 pounds per megawatt hour over a 30-year period.  It is expected that natural gas-fired combined cycles will meet the new standard.

The proposed rule would apply only to new fossil-fuel-fired electric utility generating units. The proposal would not apply to existing units including modifications such as changes needed to meet other air pollution standards. At this time, EPA has publicly announced no plans to restrict GHG emissions from existing power plants.

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

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or eliminate EPA’s authority to regulate GHGs. At this time, it is not possible to predict what legislation, if any, will ultimately emerge from Congress regarding control of GHGs.

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

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

Water Discharges

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

The Riverton Units 7 and 8 and Iatan Unit 1, which utilize once-through cooling water, were affected by regulations for Cooling Water Intake Structures issued by the EPA under the CWA Section 316(b) Phase II. The regulations became final on February 16, 2004. In accordance with these regulations, we submitted sampling and summary reports to the Kansas Department of Health and Environment (KDHE) which indicate that the effect of the cooling water intake structure on Empire Lake’s aquatic life is insignificant. KCP&L, who operates Iatan Unit 1, submitted the appropriate sampling and summary reports to the Missouri Department of Natural Resources (MDNR).

In 2007 the United States Court of Appeals for the Second Circuit remanded key sections of these CWA regulations to the EPA. As a result, the EPA suspended the regulations and revised and signed a pre-publication proposed regulation on March 28, 2011 and is obligated to finalize the rule by July 27, 2012. We will not know the full impact of these rules until they are finalized. If adopted in their present form, we expect regulations of Cooling Water Intake Structures issued by the EPA under the CWA Section 316(b) to have an impact at Riverton ranging from minor improvements to the cooling water intake structure to retirement of units 7 and 8. Impacts at Iatan 1 could range from flow velocity reductions or traveling screen modifications for fish handling to installation of a closed cycle cooling tower retrofit. Our new Iatan Unit 2 and Plum Point Unit 1 are covered by the proposed regulation but were constructed with cooling towers, the proposed Best Technology Available. We expect them to be unaffected or minimally impacted by the final rule.

Surface Impoundments

We own and maintain coal ash impoundments located at our Riverton and Asbury Power Plants. Additionally, we own a 12% interest in a coal ash impoundment at the Iatan Generating Station and a 7.52% interest in a coal ash impoundment at Plum Point. The EPA has announced its intention to revise its wastewater effluent limitation guidelines under the CWA for coal-fired power plants sometime in 2012. Once the new guidelines are issued, the EPA and states would incorporate the new standards into wastewater discharge permits, including permits for coal ash impoundments. We do not have sufficient information at this time to estimate additional costs that might result from any new standards. All of the coal ash impoundments are compliant with existing state and federal regulations.

On June 21, 2010, the EPA proposed a new regulation pursuant to the Federal Resource Conservation and Recovery Act (RCRA) governing the management and storage of Coal Combustion Residuals (CCR). In the proposal, the EPA presents two options: (1) regulation of CCR under RCRA subtitle C as a hazardous waste and (2) regulation of CCR under RCRA subtitle D as a non-hazardous waste. The public comment period closed in November 2010. It is anticipated that the final regulation will be published in mid to late 2012. We expect compliance with either option as proposed to result in the need to construct a new landfill and the conversion of existing ash handling from a wet to a dry system(s) at a potential cost of up to $15 million at our Asbury and Riverton Power Plants.

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This preliminary estimate will likely change based on the final CCR rule and its requirements. We expect resulting costs to be recoverable in our rates.

On September 23, 2010 and on November 4, 2010 representatives from GEI Consultants, on behalf of the EPA, conducted on-site inspections of our Riverton and Asbury coal ash impoundments, respectively. The consultants performed a visual inspection of the impoundments to assess the structural integrity of the berms surrounding the impoundments, requested documentation related to construction of the impoundments, and reviewed recently completed engineering evaluations of the impoundments and their structural integrity. In response to the inspection comments, a qualified engineering firm has been selected to complete the recommended geotechnical studies and install new flow monitoring devices and settlement monuments at both coal ash impoundments. The project is expected to be completed by December 2012. The project will comply with all corrective measures and recommendations made by the EPA in its site assessment reports.

Renewable Energy

As previously discussed, we have purchased power agreements with Cloud County Windfarm, LLC, located in Cloud County, Kansas and Elk River Windfarm, LLC, located in Butler County, Kansas. We do not own any portion of either windfarm.  More than 15% of the energy we put into the grid comes from these long-term Purchased Power Agreements (PPAs). 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.

Missouri regulations currently require 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. We have satisfied the current compliance requirements of the rule. Two percent of the renewable energy sources must be solar. We believe we are exempted from the solar requirement. A challenge to our exemption, brought by two of our customers and Power Source Solar, Inc., was dismissed on May 31, 2011 by the Missouri Western District Court of Appeals. The plaintiffs filed in the Missouri Supreme Court for transfer of the case from the Missouri Western District to the Missouri Supreme Court. The transfer was denied.

Renewable energy standard compliance rules were published by the MPSC on July 7, 2010.  Missouri investor-owned utilities and others initiated litigation to challenge these rules. On June 30, 2011, a Cole County Circuit Court judge ruled that portions of the MPSC rules were unlawful and unreasonable, in conflict with Missouri statute and in violation of the Missouri Constitution. Subsequent to that decision, a portion of the appeal was dropped and the entire order was stayed.  On December 27, 2011 the judge issued another order identical to the one that was stayed except that the rulings with regard to the constitutionality issue had been omitted. Kansas established a renewable portfolio standard (RPS), effective November 19, 2010. It requires 10% of our Kansas retail customer peak capacity requirements to be sourced from renewables by 2011, 15% by 2016, and 20% by 2020. In addition, there are several proposals currently before the U.S. Congress to adopt a nationwide RPS.

We have been selling the majority of our RECs and plan to continue to sell all or a portion of them moving forward. As a result of these REC sales, we cannot claim the underlying energy is renewable. Once a REC has been claimed or retired, it cannot be used for any other purpose. At the end of 2011, sufficient RECs, including hydro, were retired to comply with the Missouri and Kansas requirements through the end of November 2011. Additional RECs were retired in January of 2012 to complete the process for 2011. In the future, we will continue to retain a sufficient amount of RECs to meet any current or future RPS.

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Gas Segment

The acquisition of Missouri Gas in June 2006 involved the property transfer of two former manufactured gas plant (FMGP) sites previously owned by Aquila, Inc. and its predecessors. 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 Site #2 in Marshall, Missouri. We have incurred $0.2 million in remediation costs and estimate further remediation costs at these two FMGP 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
	2012			2011			2012			2011			2012			2011
Service cost	$	1,628		$	1,393		$	7		$	20		$	565		$	626
Interest cost	2,551			2,591			56			41			1,032			1,130
Expected return on plan assets	(3,076		)	(2,680		)	—			—			(1,041		)	(1,050		)
Amortization of prior service cost (1)	133			133			(2		)	(2		)	(253		)	(253		)
Amortization of net actuarial loss (1)	1,950			1,353			76			33			468			500
Net periodic benefit cost	$	3,186		$	2,790		$	137		$	92		$	771		$	953

	Twelve months ended March 31,
	Pension						SERP						OPEB
	2012			2011			2012			2011			2012			2011
Service cost	$	5,830		$	5,007		$	81		$	73		$	2,205		$	2,254
Interest cost	10,366			10,156			198			155			4,286			4,396
Expected return on plan assets	(11,534		)	(10,044		)	—			—			(4,148		)	(3,927		)
Amortization of prior service cost (1)	532			531			(8		)	(8		)	(1,011		)	(1,011		)
Amortization of net actuarial loss (1)	6,091			4,315			213			98			1,729			1,655
Net periodic benefit cost	$	11,285		$	9,965		$	484		$	318		$	3,061		$	3,367

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

In accordance with our regulatory agreements, our funding policy is to make contributions that are at least equal to the greater of either the minimum funding requirements of ERISA or the accrued cost of the plan. We have contributed $5.1 million to our Pension Trust in 2012 and expect our remaining 2012 contribution to be approximately $6.0 million. The actual minimum funding requirements will be determined based on the results of the actuarial valuations. 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 and time-vested restricted stock awards are valued as liability awards, in accordance with fair value guidelines. We allow employees to elect to have taxes in excess of the minimum statutory requirements withheld from their awards and, therefore, the awards are classified as liability instruments under the ASC guidance on share based payment. 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.

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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
	2012		2011		2012		2011
Compensation expense	$	822	$	741	$	1,846	$	3,136
Tax benefit recognized	298		271		642		1,143

Activity for our various stock plans for the three months ended March 31, 2012, 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,
	2012	2011
Risk-free interest rate	0.16% to 0.45%	0.61% to 1.15%
Expected volatility of Empire stock	21.5%	26.1%
Expected volatility of peer group stock	13.5% to 51.9%	21.1% to 82.2%
Expected dividend yield on Empire stock	4.9%	6.3%
Expected forfeiture rates	3%	3%
Plan cycle	3 years	3 years
Fair value percentage	41.0% to 104.0%	97.0% to 143.0%
Weighted average fair value per share	$13.63	$27.20

Non-vested restricted stock awards (based on target number) as of March 31, 2012 and 2011 and changes during the three months ended March 31, 2012 and 2011 were as follows:

	2012				2011
	Number of shares		Weighted Average Grant Date Price		Number of shares		Weighted Average Grant Date Price
Outstanding at January 1,	37,400		$	19.28	47,500		$	19.86
Granted	10,000		$	20.97	10,900		$	21.84
Awarded	(7,823	)	$	18.12	(39,621	)	$	21.92
Awarded in Excess of Target	—		—		18,621		$	21.92
Not Awarded	(5,677	)	$	18.12	—		—
Nonvested at March 31,	33,900		$	20.25	37,400		$	19.28

At March 31, 2012, there was $0.2 million of total unrecognized compensation cost related to estimated outstanding awards. This cost will be recognized over the outstanding years remaining in the vesting period.

Stock Options

Stock option grants vest upon satisfaction of service conditions. The cost of the awards is generally recognized over the requisite (explicit) service period. The fair value of the outstanding options was estimated as of March 31, 2012 and 2011, under a Black-Scholes methodology. The assumptions used in the valuations are shown below:

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	Fair Value of Grants Outstanding at March 31,
	2012	2011
Risk-free interest rate	0.17% to 0.83%	0.45% to 2.39%
Dividend yield	4.9%	6.3%
Expected volatility	25.0%	23.0%
Expected life in months	78	78
Market value	$20.35	$21.79
Weighted average fair value per option	$1.56	$1.94

	2012			2011
		Weighted Average			Weighted Average
	Options	Exercise Price		Options	Exercise Price
Outstanding at January 1,	190,300	$	21.56	267,400	$	21.69
Granted	—	$	—	—	$	—
Exercised	27,000	$	18.12	—	—
Outstanding at March 31,	163,300	$	22.13	267,400	$	21.69
Exercisable at March 31,	128,500	$	23.15	205,600	$	22.73

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, 2012 and 2011:

	2012	2011
Aggregate intrinsic value (in millions)	Less than $0.1	$0.2
Weighted-average remaining contractual life of outstanding options	3.9 years	5.8 years
Range of exercise prices	$18.36 to $23.81	$18.12 to $23.81
Total unrecognized compensation expense (in millions) related to non-vested options and related dividend equivalents granted under the plan	Less than $0.1	$0.1
Recognition period	Less than 1 year	1 to 2 years

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

Time-Vested Restricted Stock Awards

Beginning in 2011, time-vested restricted stock awards that vest after a three-year period, were granted to qualified individuals. 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, with the remainder of the award forfeited, which is distributed six months following the date of termination. 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.

No shares of time-vested restricted stock were granted in 2012 as a result of the limitation on incentive compensation in place in 2011. A summary of time vested restricted stock activity under the plan for 2011 and 2012 is presented in the table below:

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	March 31, 2012			December 31, 2011
		Weighted			Weighted
		Average Fair			Average Fair
	Number of shares	Market Value		Number of shares	Market Value
Outstanding at January 1,	3,433	$	21.84	—	$	—
Granted	—	—		10,200	$	21.84
Vested	—	—		794	$	19.32
Distributed	133	$	20.13	661	$	21.02
Forfeited	—	—		6,106	$	—
Vested but not distributed	—	—		133	$	20.13
Outstanding at end of period	3,300	$	20.35	3,433	$	21.84

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

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
	2012		2011		2012		2011
Electric transmission and distribution expense	$	4,108	$	3,823	$	15,647	$	13,992
Natural gas transmission and distribution expense	652		562		2,476		2,225
Power operation expense (other than fuel)	3,794		2,677		14,394		11,129
Customer accounts and assistance expense	2,434		2,536		10,108		11,234
Employee pension expense (1)	2,536		1,844		9,496		6,279
Employee healthcare plan (1)	2,238		1,621		8,056		7,001
General office supplies and expense	2,752		2,898		10,011		11,807
Administrative and general expense	4,219		3,647		14,868		13,126
Allowance for uncollectible accounts	593		82		3,935		3,133
Miscellaneous expense	22		25		84		164
Total	$	23,348	$	19,715	$	89,075	$	80,090

(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, Kansas and Oklahoma jurisdictions.

Note 11— Segment Information

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

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

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	For the quarter ended March 31,
	2012
	Electric		Gas		Other		Eliminations			Total
($-000’s)
Statement of Income Information
Revenues	$	119,726	$	15,683	$	1,883	$	(148	)	$	137,144
Depreciation and amortization	13,569		919		447		—			14,935
Federal and state income taxes	5,187		697		315		—			6,199
Operating income	18,243		2,054		513		—			20,810
Interest income	170		72		—		(63		)	179
Interest expense	10,027		977		—		(63		)	10,941
Income from AFUDC (debt and equity)	98		—		—		—			98
Net income	8,173		1,119		512		—			9,804
Capital Expenditures	$	34,079	$	725	$	944	$	—		$	35,748

	For the quarter ended March 31,
	2011
	Electric		Gas		Other		Eliminations			Total
($-000’s)
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 twelve months ended March 31,
	2012
	Electric		Gas		Other		Eliminations			Total
($-000’s)
Statement of Income Information
Revenues	$	515,641	$	41,124	$	7,113	$	(592	)	$	563,286
Depreciation and amortization	55,778		3,539		1,821		—			61,138
Federal and state income taxes	31,197		991		1,064		—			33,252
Operating income	88,557		5,374		1,966		—			95,897
Interest income	702		260		—		(250		)	712
Interest expense	39,086		3,910		5		(250		)	42,751
Income from AFUDC (debt and equity)	583		3		—		—			586
Net income	49,542		1,582		1,730		—			52,854
Capital Expenditures	$	110,728	$	4,507	$	4,133	$	—		$	119,368

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	For the twelve months ended March 31,
	2011
	Electric		Gas		Other		Eliminations			Total
($-000’s)
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

	As of March 31, 2012
	Electric		Gas(1)		Other		Eliminations			Total
($-000’s)
Balance Sheet Information
Total assets	$	1,940,782	$	146,331	$	27,047	$	(87,701	)	$	2,026,459

(1) Includes goodwill of $39,492.

	As of December 31, 2011
	Electric		Gas(1)		Other		Eliminations			Total
($-000’s)
Balance Sheet Information
Total assets	$	1,931,320	$	145,897	$	26,038	$	(81,420	)	$	2,021,835

(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
	2012			2011			2012			2011
Consolidated provision for income taxes	$	6.2		$	7.3		$	33.3		$	27.8
Consolidated effective federal and state income tax rates	38.7		%	37.8		%	38.6		%	35.4		%

The effective tax rate for the first quarter of 2012 is higher than 2011 mainly due to tax rates associated with lower pre-tax income. The 2012 twelve months ended March 31, 2012 effective tax is higher than the 2011 comparable period primarily due to substantially lower AFUDC income.

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. We increased our current tax liability by $10.0 million during 2010 in recognition that the $26.6 million payment may be considered taxable income in 2010.  An agreement was reached with the IRS in 2011 that allowed us to defer recognition for tax purposes of approximately $26.1 million utilizing involuntary conversion rules within the Code. Accordingly, we reduced our current tax liability based on the agreement and will recognize the $26.1 million for tax purposes over more than 50 years.

We do not have any unrecognized tax benefits as of March 31, 2012. We recognized interest or penalties of $0.0 million and $0.1 million during 2011 and 2010, respectively, related to

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unrecognized tax benefits in other expenses and on the balance sheet. We do not expect any significant changes to our unrecognized tax benefits over the next twelve months.

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 45 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, 2012, our gross operating revenues were derived as follows:

Electric segment sales*	91.5	%
Gas segment sales	7.3
Other segment sales	1.2

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

Earnings

During the first quarter of 2012, basic and diluted earnings per weighted average share of common stock were $0.23 on net income of $9.8 million, as compared to $0.29 on net income of $11.9 million in the first quarter of 2011. For the twelve months ended March 31, 2012, basic and diluted earnings per weighted average share of common stock were $1.26 on net income of $52.9 million as compared to $1.23 on net income of $50.7 million for the twelve months ended March 31, 2011.

Weather was the primary driver for the quarter with the warmest temperatures on record. This negatively impacted both electric and gas margins. We define electric gross margins as electric revenues less fuel and purchased power costs. We define gas gross margins as gas operating revenues less cost of gas in rates. The weather impact was mitigated for the electric segment, as Missouri rates, which became effective in June 2011, increased margins, offsetting the effect of weather when compared to last year. Other operating and maintenance expenses also increased over last year, negatively impacting net income.

The twelve month ending period results were positively impacted by rate increases and unseasonably hot weather in June and July of 2011, more than offsetting the impacts of the mild weather in the fourth quarter of 2011 and the first quarter of 2012 and the loss of customers from the May 2011 tornado. Increased operating and maintenance expenses decreased earnings, primarily reflecting the added expenses for Iatan 2 and Plum Point and the ending of our construction accounting expense deferral on June 15, 2011. Changes in AFUDC amounts and in effective income tax rates also negatively impacted earnings during the twelve month ending period. Factors impacting gross margin and net income for the quarter and twelve months ending March 31, 2012, are presented on a segment basis under Results of Operations below.

The table below sets forth a reconciliation of basic and diluted earnings per share between the three months and twelve months ended March 31, 2011 and March 31, 2012, 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.

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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. The dilutive effect of additional shares issued included in the table reflects the estimated impact of all shares issued during the periods.

	Three Months Ended			Twelve Months Ended
Earnings Per Share — 2011	$	0.29		$	1.23
Revenues
Electric segment	$	(0.13	)	$	0.26
Gas segment	(0.08		)	(0.10		)
Other segment	0.01			0.01
Total Revenue	(0.20		)	0.17
Electric fuel and purchased power	0.13			0.18
Cost of natural gas sold and transported	0.05			0.07
Margin	(0.02		)	0.42
Operating — electric segment	(0.05		)	(0.15		)
Operating —gas segment	0.00			0.01
Operating —other segment	(0.01		)	0.00
Maintenance and repairs	0.00			(0.04		)
Depreciation and amortization	0.04			0.03
Other taxes	0.00			(0.03		)
Interest charges	(0.02		)	(0.03		)
AFUDC	0.00			(0.09		)
Change in effective income tax rates	0.00			(0.07		)
Dilutive effect of additional shares issued	0.00			(0.02		)
Earnings Per Share — 2012	$	0.23		$	1.26

Recent Activities

Tornado Recovery and Activity

Joplin, Missouri continues to recover from the May 22, 2011 tornado. As of March 31, 2012, our system-wide customer count is down by approximately 1,400 as compared to the customer count levels prior to the May 22 storm. Storm restoration costs were approximately $21.4 million as of March 31, 2012. The majority of these costs have been capitalized. We expect to spend an additional $6.5 million to rebuild our destroyed substation, but anticipate insurance proceeds will cover most of this cost. We expect the loss of electric load and corresponding revenues to abate as customers rebuild. As we continue to add customers back to our system, our customer growth expectations range from approximately 0.5% to 1.1% over the next several years.

On February 29, 2012, tornadoes struck the Branson and Bolivar, Missouri areas of our service territory leaving approximately 9,400 customers without power. Power had been restored to all but approximately 500 of those customers by the next day. By March 4, 2012, power had been restored to all customers that could receive service. At the end of March, due to severe structural damage, approximately 150 customers in Buffalo and Branson were still unable to take service.

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Financings

On April 1, 2012, we redeemed all $74.8 million aggregate principal amount of our First Mortgage Bonds, 7.00% Series due 2024, which is classified as a current liability on the March 31, 2012 balance sheet. All $5.2 million of our First Mortgage Bonds, 5.20% Pollution Control Series due 2013, and all $8.0 million of our First Mortgage Bonds, 5.30% Pollution Control Series due 2013 were also redeemed with payment made to the trustee prior to March 31, 2012.

To replace this financing, as described in Note 6, on April 2, 2012, we entered into a Bond Purchase Agreement for a private placement of $88 million aggregate principal amount of 3.58% First Mortgage Bonds due April 2, 2027. The first settlement of $38 million occurred on April 2, 2012 and a second settlement of $50 million is anticipated to occur on or about June 1, 2012. The bonds will mature on April 2, 2027. Interest is payable semi-annually on the bonds on each April 2 and October 2, commencing October 2, 2012.

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, 2012, compared to the same periods ended March 31, 2011.

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
	2012		2011		2012		2011
Electric	$	8.2	$	9.3	$	49.6	$	46.6
Gas	1.1		2.2		1.6		2.5
Other	0.5		0.4		1.7		1.6
Net income	$	9.8	$	11.9	$	52.9	$	50.7

Electric Segment

Overview

Our electric segment income for the first quarter of 2012 was $8.2 million as compared to $9.3 million for the first quarter of 2011, a decrease of $1.1 million. As mentioned previously, weather had a significant negative impact on the quarter, but was partially offset by positive results from rate increases. Operating expense increased, but was offset by decreased depreciation compared to last year.

As shown in the table below, electric segment gross margin increased approximately $0.4 million during the first quarter of 2012 as compared to the first quarter of 2011 mainly due to increased rates, offset by decreased demand resulting from mild weather in the first quarter of 2012. 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 2012 were 29.3% less than the same period last year and 26.4% less than the 30-year average.

As shown in the table below, the electric gross margin increased approximately $28.2 million for the twelve months ended March 31, 2012 as compared to the same period in 2011, mainly due to increased revenues resulting from the June 2011 and September 2010 Missouri rate increases, the July 2010 Kansas rate increase, the September 2010 and March 2011 Oklahoma rate increases and the April 2011 Arkansas rate increase. Decreased demand, resulting from the mild weather in the first quarter of 2012 and fourth quarter of 2011 negatively impacted margins.

The table below represents our electric gross margins for the applicable periods ended March 31 (dollars in millions):

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	Quarter Ended						Twelve Months Ended
	2012			2011			2012			2011
Electric segment revenues	$	119.7		$	128.4		$	515.6		$	499.0
Fuel and purchased power	45.2			54.2			191.3			202.8
Electric segment gross margins	$	74.5		$	74.2		$	324.3		$	296.2
Margin as % of total electric segment revenues	62.2		%	57.8		%	62.9		%	59.4		%

Although a non-GAAP presentation, we believe the presentation of gross margin is useful to investors and others in understanding and analyzing changes in our electric operating performance from one period to the next, and have included the analysis 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.

Sales and Revenues

Electric operating revenues comprised approximately 87.0% of our total operating revenues during the first quarter of 2012. Electric operating revenues for the first quarter of 2012 and 2011 were comprised of the following:

	2012		2011
Residential	45.5	%	46.4	%
Commercial	28.8		26.8
Industrial	15.1		13.0
Wholesale on-system	3.3		3.3
Wholesale off-system	2.7		6.2
Miscellaneous sources*	2.9		2.6
Other electric revenues	1.7		1.7

*primarily public authorities

The amounts and percentage changes from the prior periods in kilowatt-hour (kWh) sales by major customer class for on-system and off-system sales for the applicable periods ended March 31, were as follows:

	kWh Sales  (in millions)
	First	First			12 Months	12 Months
	Quarter	Quarter	%		Ended	Ended	%
Customer Class	2012	2011	Change(1)		2012	2011	Change(1)
Residential	476.5	591.4	(19.4	)%	1,867.8	2,012.6	(7.2	)%
Commercial	337.8	375.7	(10.1	)	1,538.5	1,634.9	(5.9	)
Industrial	241.7	237.0	1.9		1,027.4	1,013.1	1.4
Wholesale on-system	84.5	87.6	(3.6	)	361.7	358.4	0.9
Other(2)	31.2	33.3	(6.1	)	126.7	125.8	0.7
Total on-system sales	1,171.7	1,325.0	(11.6	)	4,922.1	5,144.8	(4.3	)
Off-system	136.8	257.9	(47.0	)	618.8	873.5	(29.2	)
Total kWh Sales	1,308.5	1,582.9	(17.3	)	5,540.9	6,018.3	(7.9	)

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

(2) Other kWh sales include street lighting, other public authorities and interdepartmental usage.

KWh sales for our on-system customers decreased during the first quarter of 2012 as compared to the first quarter of 2011, primarily due to decreased demand resulting from mild weather in the first quarter of 2012. The decrease in residential kWh sales was also due to the loss of residences in the May 22, 2011 tornado and the decrease in commercial kWh sales was mainly due to the loss of businesses in the May 2011 tornado.

KWh sales for our on-system customers decreased during the twelve months ended March 31, 2012, as compared to the same period in 2011, primarily due to decreased demand resulting from mild weather in the first quarter of 2012, partially offset by increased demand resulting from

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unseasonably hot weather in June and July of 2011. Residential and commercial kWh sales decreased primarily due to the mild weather in the first quarter of 2012 and the loss of residences and businesses in the May 22, 2011 tornado.

The amounts and percentage changes from the prior periods in 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:

	Electric Segment Operating Revenues (in millions)
	First		First				12 Months		12 Months
	Quarter		Quarter		%		Ended		Ended		%
Customer Class	2012		2011		Change(1)		2012		2011		Change(1)
Residential	$	54.2	$	59.4	(8.7	)%	$	216.5	$	210.3	3.0	%
Commercial	34.4		34.3		0.3		157.5		150.9		4.4
Industrial	18.0		16.7		8.4		80.3		72.3		11.2
Wholesale on-system	4.0		4.2		(6.7	)	18.9		18.5		1.7
Other(2)	3.4		3.3		4.3		14.0		12.7		10.0
Total on-system revenues	$	114.0	$	117.9	(3.2	)	$	487.2	$	464.7	4.8
Off-system	3.2		7.9		(59.4	)	18.6		24.6		(24.7	)
Total Revenues from kWh Sales	117.2		125.8		(6.8	)	505.8		489.3		3.4
Miscellaneous Revenues(3)	2.1		2.1		(3.1	)	8.1		7.9		2.7
Total Electric Operating Revenues	$	119.3	$	127.9	(6.7	)	$	513.9	$	497.2	3.3
Water Revenues	0.4		0.4		(4.5	)	1.7		1.8		(2.6	)
Total Electric Segment Operating
Revenues	$	119.7	$	128.3	(6.7	)	$	515.6	$	499.0	3.3

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

(2) Other operating revenues include street lighting, other public authorities and interdepartmental usage.

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

Revenues for our on-system customers decreased $3.8 million during the first quarter of 2012 as compared to the first quarter of 2011 primarily due to record mild weather. The impact of weather and other related factors decreased revenues an estimated $13.7 million. Decreased customer counts, primarily resulting from the May 2011 tornado, reduced revenues an estimated $1.9 million. Rate changes, primarily the June 2011 Missouri rate increase, the March 2011 Oklahoma rate increase and the April 2011 Arkansas rate increase contributed an estimated $11.8 million to revenues. Commercial and industrial revenues, which are less weather sensitive than residential and wholesale revenues, increased mainly due to the rate increases.

Revenues for our on-system customers increased $22.5 million for the twelve months ended March 31, 2012. Rate changes, primarily the September 2010 and June 2011 Missouri rate increases, the July 2010 Kansas rate increase, the September 2010 and March 2011 Oklahoma rate increases and the April 2011 Arkansas rate increase, contributed an estimated $45.0 million to revenues. Decreased customer counts, primarily resulting from the May 2011 tornado, reduced revenues an estimated $10.6 million. Weather and other related factors decreased revenues an estimated $11.9 million primarily due to mild weather in the first quarter of 2012 and the fourth quarter of 2011, offsetting unseasonably hot weather in June and July of 2011.

Off-System Electric Transactions.

In addition to sales to our own customers, we also sell power to other utilities as available, including through the Southwest Power Pool (SPP) Energy Imbalance Services (EIS) market. See “— Competition” below. The majority of our off-system sales margins are 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 margin or net income.

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Operating Revenue Deductions — Fuel and Purchased Power

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 incomes for the applicable periods ended March 31, 2012 and 2011. As shown below, fuel and purchased power costs decreased in both periods mainly due to decreased volumes primarily due to decreased demand in the first quarter of 2012 resulting from record mild weather.

	Three Months Ended						Twelve Months Ended
(in millions)	2012			2011			2012			2011
Actual fuel and purchased power expenditures	$	40.7		50.3			$	186.8		$	197.2
Missouri fuel adjustment recovery (1)	4.3			2.9			8.6			6.5
Missouri fuel adjustment deferral(2)	1.8			1.1			(2.0		)	(1.6		)
Kansas and Oklahoma regulatory adjustments(2)	0.3			0.1			(0.3		)	0.3
SWPA amortization(3)	(0.7		)	—			(2.1		)	—
Unrealized (gain)/loss on derivatives	(1.2		)	(0.2		)	0.3			0.4
Total fuel and purchased power expense per income statement	$	45.2		$	54.2		$	191.3		$	202.8

(1) Recovered from customers from prior deferral period.

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

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

Operating Revenue Deductions — Other Than Fuel and Purchased Power

The table below shows regulated operating expense changes during the first quarter of 2012 and the twelve months ended March 31, 2012 as compared to the same periods in 2011.

	Three Months Ended		Twelve Months Ended
(in millions)	2012 vs. 2011		2012 vs. 2011
Employee pension expense	$	0.7	$	3.2
Steam power other operating expense(1)	1.0		2.9
Transmission expense	0.3		1.7
Employee health care expense	0.6		1.0
Uncollectible accounts	0.4		0.9
Regulatory commission expense	—		0.9
Property insurance	—		0.4
Injuries and damages expense	—		0.4
General labor costs	—		(1.9		)
Professional services	0.3		(0.9		)
Other miscellaneous accounts (netted)	0.2		0.8
TOTAL	$	3.5	$	9.4

(1) ) Reflects recognition of costs of new plant after deferral ended June 15, 2011, the effective date of rates for our 2010 Missouri rate case.

The table below shows maintenance and repairs expense changes during the first quarter of 2012 and the twelve months ended March 31, 2012 compared to the same periods in 2011.

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	Three Months Ended			Twelve Months Ended
(in millions)	2012 vs. 2011			2011 vs. 2010
Distribution and transmission maintenance costs	$	0.1		$	1.4
Maintenance and repairs expense to the SLCC(1)	(0.3		)	1.1
Maintenance and repairs expense at the Iatan plant	(0.3		)	0.6
Maintenance and repairs expense at the Plum Point plant	0.1			0.5
Maintenance and repairs expense at the Riverton plant	0.4			(0.8		)
Other miscellaneous accounts (netted)	(0.1		)	(0.1		)
TOTAL	$	(0.1	)	$	2.7

(1)Mainly due to a transformer failure in December 2011.

Depreciation and amortization expense decreased approximately $2.5 million (15.3%) during the quarter. This reflects a decrease in regulatory amortization expense of $3.6 million offset by increased depreciation of $0.4 million due to increased plant in service during the first quarter of 2012 and an increase of $0.7 million in deferred depreciation.

Depreciation and amortization expense decreased approximately $1.9 million (3.3%) during the twelve months ended March 31, 2012. This reflects a decrease in regulatory amortization expense due to the termination of construction accounting as of June 15, 2011, the effective date of rates for our 2010 Missouri rate case.

Other taxes increased approximately $0.1 million during the first quarter of 2012 due to increased property tax reflecting our additions to plant in service and increased municipal franchise taxes.

Other taxes increased approximately $2.1 million during the twelve months ended March 31, 2012 due to increased property tax reflecting our additions to plant in service and increased municipal franchise taxes.

Gas Segment

Gas Operating Revenues and Sales

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

	Total Gas Delivered to Customers
	Three Months Ended				Twelve Months Ended
(bcf sales)	2012	2011	% change		2012	2011	% change
Residential	0.96	1.40	(31.2	)%	2.13	2.56	(17.0	)%
Commercial	0.45	0.63	(29.2	)	1.08	1.24	(12.5	)
Industrial(1)	0.03	0.05	(40.4	)	0.08	0.11	(23.1	)
Other(2)	0.01	0.02	(35.1	)	0.03	0.03	(19.8	)
Total retail sales	1.45	2.10	(30.8	)	3.32	3.94	(15.8	)
Transportation sales(1)	1.22	1.48	(17.8	)	4.26	4.71	(9.5	)
Total gas operating sales	2.67	3.58	(25.4	)	7.58	8.65	(12.3	)

Gas retail sales decreased 31.2% during the first quarter of 2012 as compared to 2011 primarily due to mild weather during the first quarter of 2012. The winter months are normally high sales months for the natural gas business, whose heating season runs from November to March of each year. However, heating degree days were 34.3% less in the first quarter of 2012 as compared to the first quarter of 2011 and 29.2% less than the 30-year average. Industrial sales decreased during the first quarter of 2012 reflecting the transfer of customers from industrial sales to transportation.

Gas retail sales decreased during the twelve months ended March 31, 2012 reflecting the mild weather in the first quarter of 2012 and customer contraction of 1.1%. Industrial sales decreased reflecting the transfer of customers from industrial sales to transportation during the first quarter of 2012.

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	Operating Revenues and Cost of Gas Sold
	Three Months Ended						Twelve Months Ended
($ in millions)	2012		2011		% change		2012		2011		% change
Residential	$	10.1	$	13.5	(25.6	)%	$	25.5	$	29.5	(13.4	)%
Commercial	4.3		5.7		(25.8	)	11.0		12.5		(12.0	)
Industrial(1)	0.2		0.3		(32.0	)	0.6		0.8		(22.7	)
Other(2)	0.1		0.2		(30.6	)	0.3		0.3		(14.9	)
Total retail revenues	$	14.7	$	19.7	(25.8	)	$	37.4	$	43.1	(13.2	)
Other revenues	0.1		0.1		(1.3	)	0.5		0.5		(1.8	)
Transportation revenues(1)	0.9		1.2		(18.7	)	3.2		3.7		(13.2	)
Total gas operating revenues	$	15.7	$	21.0	(25.3	)	$	41.1	$	47.3	(13.1	)
Cost of gas sold	8.6		12.0		(28.7	)	19.3		23.5		(18.0	)
Gas operating revenues over cost of gas in rates (margin)	$	7.1	$	9.0	(20.6	)	$	21.8	$	23.8	(8.2	)

(1) Percentage change reflects a large volume customer switching from industrial sales to transportation in the first quarter of 2012.

(2) Other includes other public authorities and interdepartmental usage.

During the first quarter of 2012, gas segment revenues decreased approximately $5.3 million, mainly due to decreased sales resulting from mild weather during the quarter. During the first quarter of 2012, our PGA revenue (which represents the cost of gas recovered from our customers) was approximately $8.6 million as compared to $12.0 million in the first quarter of 2011, a decrease of approximately $3.4 million. Our margin (defined as gas operating revenues less cost of gas in rates) was $1.9 million less in the first quarter of 2012 as compared to the same period in 2011, due to the weather impact.

During the twelve months ended March 31, 2012, gas segment revenues decreased approximately $6.2 million, mainly due to the first quarter decrease in sales. During the twelve months ended March 31, 2012, our PGA revenue was approximately $19.3 million as compared to $23.5 million during the twelve months ended March 31, 2011, a decrease of approximately $4.2 million. Our margin for the twelve months ended March 31, 2012 decreased $2.0 million as compared to the same period in 2011.

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, 2012, we had unrecovered purchased gas costs of $0.2 million recorded as a current regulatory asset and $0.6 million recorded as a non-current regulatory asset.

Operating Revenue Deductions

Quarter. Total other operating expenses were $2.2 million during the first quarter of 2012 as compared to $2.1 million in the first quarter of 2011, primarily due to a $0.1 million increase in uncollectible accounts.

Our gas segment had net income of $1.1 million for the first quarter of 2012 as compared to $2.2 million for the first quarter of 2011.

Twelve Months Ended. Total other operating expenses were $8.4 million for the twelve months ended March 31, 2012 as compared to $8.9 million for the twelve months ended March 31, 2011. This decrease was mainly due to a $0.2 million decrease in general labor costs, a $0.2 million decrease in customer accounts expense and a $0.2 million decrease in rent expense, partially offset by a $0.2 million increase in transmission and distribution expense.

Our gas segment had net income of $1.6 million for the twelve months ended March 31, 2012 as compared to $2.5 million for the twelve months ended March 31, 2011.

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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:

	Three Months Ended						Twelve Months Ended
	2012			2011			2012			2011
Consolidated provision for income taxes	$	6.2		$	7.3		$	33.3		$	27.8
Consolidated effective federal and state income tax rates	38.7		%	37.8		%	38.6		%	35.4		%

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

Nonoperating Items

The following table shows the total allowance for funds used during construction (AFUDC) for the applicable periods ended March 31. AFUDC was virtually the same for the first quarter of 2012 and the first quarter of 2011 and decreased significantly for the twelve months ended March 31, 2012 as compared to the same period in 2011 reflecting the completion of Iatan 2 and the Plum Point Energy Station in late 2010.

	Three Months Ended				Twelve Months Ended
($ in millions)	2012		2011		2012		2011
Allowance for equity funds used during construction	$	0.1	$	—	$	0.4	$	2.8
Allowance for borrowed funds used during construction	—		—		0.2		3.2
Total AFUDC	$	0.1	$	—	$	0.6	$	6.0

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

	Interest Charges
	($ in millions)
	3 Months		3 Months					12 Months			12 Months
	Ended		Ended			%		Ended			Ended			%
	2012		2011			Change		2012			2011			Change
Long-term debt interest	$	10.7	$	10.6		0.2	%	$	42.6		$	42.1		1.2	%
Short-term debt interest	0.0		0.0			(3.8	)	0.1			0.4			(79.6	)
Trust preferred securities interest	—		—			—		—			1.0			(100.0	)
Iatan 1 and 2 carrying charges*	—		(1.1		)	(100.0	)	(0.9		)	(3.7		)	76.1
Other interest	0.2		0.2			6.8		1.0			0.8			14.3
Total interest charges	$	10.9	$	9.7		12.7		$	42.8		$	40.6		5.2

*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 allowed deferral of certain costs until the environmental upgrades to Iatan 1 were included in our rate base. We began deferring Iatan 2 carrying charges in the third quarter of 2010. Deferral ended when the plant was placed in rates. Iatan 1 was placed in rates in September 2010. Iatan 2 was placed in rates June 15,  2011. See Note 3 and Rate Matters below for additional information regarding carrying charges.

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

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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 (commonly referred to as “regulatory 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, 2009:

Jurisdiction	Date Requested	Annual Increase Granted		Percent Increase Granted		Date Effective
Missouri — Electric	September 28, 2010	$	18,700,000	4.70	%	June 15, 2011
Missouri — Electric	October 29, 2009	$	46,800,000	13.40	%	September 10, 2010
Kansas — Electric	June 17, 2011	$	1,250,000	5.20	%	January 1, 2012
Kansas — Electric	November 4, 2009	$	2,800,000	12.40	%	July 1, 2010
Oklahoma — Electric	June 30, 2011	$	240,722	1.66	%	January 4, 2012
Oklahoma — Electric	January 28, 2011	$	1,063,100	9.32	%	March 1, 2011
Oklahoma — Electric	March 25, 2010	$	1,456,979	15.70	%	September 1, 2010
Arkansas - Electric	August 19, 2010	$	2,104,321	19.00	%	April 13, 2011
Missouri — Gas	June 5, 2009	$	2,600,000	4.37	%	April 1, 2010

On April 16, 2012, we filed a Notice of Intended Case Filing with the MPSC of our intentions to file an electric rate case in Missouri as early as July 1, 2012.

On March 19, 2012, we filed a Notice of Intended Case Filing for our water operations with the MPSC stating our intention to initiate a small utility rate case proceeding seeking an increase in our water rates by the end of May, 2012.

Our rate cases, as we reported in our Annual Report on Form 10-K for the year ended December 31, 2011, remain unchanged. See Note 3, “Regulatory Matters” in our Annual Report on Form 10-K for the year ended December 31, 2011 for additional information

COMPETITION

Electric Segment

SPP-RTO

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

Day Ahead Market:  The SPP RTO will implement a Day-Ahead Market, with unit commitment and co-optimized ancillary services market, in March 2014. As part of the Day-Ahead Market, the SPP RTO will create, prior to implementation of such market, a single NERC approved balancing authority to take over balancing authority responsibilities for its members, including Empire, which is expected to provide operational and economic benefits for our customers. The Day-Ahead Market would replace the existing EIS market described above.

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SPP Regional Transmission Development: On June 17, 2010, the FERC approved the new highway/byway cost allocation method. This is a new transmission cost allocation method to replace the existing FERC accepted cost allocation method for new transmission facilities needed to continue to reliably and economically serve SPP customers, including ours, well into the future.  Prior to FERC approval, we and other SPP members had filed a joint protest at the FERC based on our disagreement with the SPP on the allocation percentages and various other issues. Following the approval, we and other SPP members requested a rehearing. On October 20, 2011, the FERC issued its Order on Rehearing denying our request. In mid December 2011, we, along with the other SPP member joint protestors, filed a Petition for Review and Motion for Stay of Procedures with the U. S. Court of Appeals for the Eighth Circuit. We are concerned with the SPP’s authority, pursuant to the FERC Order, to allocate to us the costs of transmission projects from which we would receive either no benefits or benefits that are not roughly commensurate with the allocated costs. We requested a stay of procedures in order to allow the SPP to complete its efforts to adopt a method satisfactory to us for analyzing the reasonableness of the highway/byway cost allocation approach and an effective remediation process for imbalanced cost allocations. On December 16, 2011, the Eighth Circuit U.S. Court of Appeals granted our petition and stay request. On April 4, 2012, we and the other petitioners filed a status report and motion for voluntary dismissal of the petition. Our decision to dismiss the petition is based on the January 2012 approvals of the SPP Board of Directors (BOD) and Regional State Committee of the regional cost allocation imbalance review process and policy with specific direction given to SPP to implement the recommendations and review process in 2013. Although there are steps yet to be taken to implement the cost allocation imbalance review and remediation process, we believe that withdrawal of the petition was warranted. On April 5, 2012, the Eighth Circuit granted our motion to dismiss and, on April 10, 2012, amended their judgment of the granting of dismissal to clarify that such dismissal would not preclude us from raising similar concerns of any future FERC order. On January 31, 2012, the SPP’s BOD approved an additional $1.7 billion in highway/byway projects to be constructed by 2022, which would be included in the regional cost allocation review process. As these projects are constructed, we will be allocated a share of the costs of the projects subject to the FERC accepted cost allocation method referred to above. We expect that these operating costs will be material, but expect that they will be recoverable in future rates.

Other FERC Activity

On July 21, 2011, the FERC issued Order No. 1000 (Transmission Planning and Cost Allocation by Transmission Owning and Operating Public Utilities). Order 1000 requires all public utility transmission providers to (among other things) facilitate non-incumbent transmission developer participation in regional transmission planning by removing from FERC-approved tariffs and agreements any language creating a federal Right of First Refusal (ROFR) for an incumbent transmission provider to construct transmission facilities selected in a regional transmission plan for cost allocation. As a transmission owning member of the SPP RTO, this could directly affect our rights to build transmission facilities within our service territory. A second key element of Order 1000 directed transmission providers to develop policy and procedures for interregional transmission coordination and interregional cost allocation. Since we are on the southeastern seam of the SPP, this policy will most likely have a direct impact on our customers, primarily through a potential reduction to our production costs as a result of greater access to lower cost power from within the SPP, and across this seam and the possible reduction because of the cost sharing for new transmission projects. SPP stakeholder processes have commenced for the compliance filings and we will continue to participate in the SPP stakeholder processes to understand the impact of Order 1000 on our ability to construct new facilities within our service territory as well as its influence on promoting construction of transmission projects on or near our borders with our neighbors. Compliance filings by the SPP to address the ROFR requirements are currently scheduled to be due October 11, 2012 and April 13, 2013 for interregional/seams planning and cost allocation. It is anticipated that the SPP will be filing for an extension of the October 2012 ROFR filing deadline to better accommodate the SPP’s normal cycle of board of directors and stakeholder meetings.

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See Note 3, “Regulatory Matters - Competition” in our Annual Report on Form 10-K for the year ended December 31, 2011 for additional information.

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 2012 for our budgeted capital expenditures (as discussed in “Capital Requirements and Investing Activities” below). We believe the amounts available to us under our credit facilities and the issuance of debt and equity securities together with this cash provided by operating activities will allow us to meet our needs for working capital, pension contributions, our continuing construction expenditures, anticipated debt redemptions, interest payments on debt obligations, dividend payments and other cash needs through the next several years.

We will continue to evaluate our need to increase available liquidity based on our view of working capital requirements, including the timing of our construction programs, impacts of the 2011 tornado and other factors. See Item 1A, “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2011 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)	2012			2011			Change
Cash provided by/(used in):
Operating activities	$	39.1		$	34.0		$	5.1
Investing activities	(31.0		)	(17.2		)	(13.8		)
Financing activities	(11.2		)	(23.5		)	12.3
Net change in cash and cash equivalents	$	(3.1	)	$	(6.7	)	$	3.6

Cash flow from Operating Activities

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

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

First Quarter 2012 Compared to 2011.  During the first quarter of 2012, our net cash flow provided from operating activities was $39.1 million, an increase of $5.1 million or 15.0% from 2011. This change resulted from the following:

·Changes in net income - $(2.1) million.

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·Changes in depreciation and amortization mostly reflecting increased plant in service and amortization of Missouri fuel components - $2.0 million.

·Reduced pension contributions - $11.4 million.

·Lower deferrals of income tax mostly reflecting changes in depreciation estimates — $(2.1) million.

·Changes in accounts payable reflecting increased payments partially due to property tax payments - $(3.2) million.

Capital Requirements and Investing Activities

Our net cash flows used in investing activities increased $13.8 million during the first quarter of 2012 as compared to the first quarter of 2011.

Our capital expenditures incurred totaled approximately $34.7 million during the first quarter of 2012 compared to $17.5 million in the first quarter of 2011. The increase was primarily the result of an increase in electric plant additions and replacements, mainly due to the environmental retrofit in progress at our Asbury plant and an increase in storm costs mainly due to the tornadoes that struck the Branson and Bolivar, Missouri areas of our service territory in February, 2012.

A breakdown of the capital expenditures for the quarters ended March 31, 2012 and 2011 is as follows:

	Capital Expenditures
(in millions)	2012			2011
Distribution and transmission system additions	$	12.9		$	10.9
New Generation — Plum Point Energy Station	—			(0.2		)
New Generation — Iatan 2	0.8			1.9
Additions and replacements — electric plant	10.6			1.8
Gas segment additions and replacements	0.6			0.2
Storms	3.5			—
Transportation	0.3			0.4
Other (including retirements and salvage - net) (1)	5.0			2.1
Subtotal	33.7			17.1
Non-regulated capital expenditures (primarily fiber optics)	1.0			0.4
Subtotal capital expenditures incurred (2)	34.7			17.5
Adjusted for capital expenditures payable (3)	(3.7		)	(0.3		)
Total cash outlay	$	31.0		$	17.2

(1)  Other includes no equity AFUDC for 2012 or 2011.

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

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

Approximately 92% of our cash requirements for capital expenditures during the first quarter of 2012 were satisfied internally from operations (funds provided by operating activities less dividends paid).

We estimate that internally generated funds will provide approximately 72% of the funds required for the remainder of our budgeted 2012 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).”

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Financing Activities

Our net cash flows used in financing activities increased $12.3 million in the first quarter of 2012 as compared to 2011.

On April 1, 2012, we redeemed all $74.8 million aggregate principal amount of our First Mortgage Bonds, 7.00% Series due 2024, which is classified as a current liability on the March 31, 2012 balance sheet. All $5.2 million of our First Mortgage Bonds, 5.20% Pollution Control Series due 2013, and all $8.0 million of our First Mortgage Bonds, 5.30% Pollution Control Series due 2013 were also redeemed with payment made to the trustee prior to March 31, 2012.

On April 2, 2012, we entered into a Bond Purchase Agreement for a private placement of $88 million aggregate principal amount of 3.58% First Mortgage Bonds due April 2, 2027. The first settlement of $38 million occurred on April 2, 2012 and a second settlement of $50 million is anticipated to occur on or about June 1, 2012. The bonds will mature on April 2, 2027. Interest is payable semi-annually on the bonds on each April 2 and October 2, commencing October 2, 2012. The bonds may be redeemed, at our option, at any time prior to maturity, at par plus a make whole premium, together with accrued and unpaid interest, if any, to the redemption date. The bonds have not been registered under the Securities Act of 1933, as amended, and may not be offered or sold in the United States absent registration or an applicable exemption from registration requirements. We will use the proceeds from the sale of these bonds to redeem the called bonds discussed above (including to repay short term debt initially used for such purpose). The bonds have been and will be issued under the EDE mortgage.

We have a $400 million shelf registration statement with the SEC, effective February 7, 2011, covering our common stock, unsecured debt securities, preference stock, and first mortgage bonds. We have received regulatory approval for the issuance of securities under this shelf from all four states in our electric service territory, but we may only issue up to $250 million of such securities in the form of first mortgage bonds, of which $212 million remains available, although $50 million is committed due to the financing discussed above. We plan to use proceeds from offerings made pursuant to this shelf to fund capital expenditures, refinancings of existing debt or general corporate needs during the three-year effective period.

On January 17, 2012, we entered into the Third Amended and Restated Unsecured Credit Agreement which amended and restated our Second Amended and Restated Unsecured Credit Agreement dated January 26, 2010. This agreement extended the termination date of the revolving credit facility from January 26, 2013 to January 17, 2017. The agreement also removed the letter of credit facility and includes a swingline loan facility with a $15 million swingline loan sublimit. The aggregate amount of the revolving credit commitments remains $150 million, inclusive of the $15 million swingline loan sublimit. In addition, the pricing and fees under the facility were amended. Interest on borrowings under the facility accrues at a rate equal to, at our option, (i) the highest of (A) the bank’s prime commercial rate, (B) the federal funds effective rate plus 0.5% or (C) one month LIBOR plus 1.0%, plus a margin or (ii) one month, two month or three month LIBOR, in each case, plus a margin. Each margin is based on our current credit ratings and the pricing schedule in the facility. As of the date hereof, and based on our current credit ratings, the LIBOR margin under the facility decreased from 2.70% to 1.25%. A facility fee is payable quarterly on the full amount of the commitments under the facility based on our current credit ratings, which fee is currently 0.25%. In addition, upon entering into the amended and restated facility, we paid an upfront fee to the revolving credit banks of $262,500 in the aggregate. There were no other material changes to the terms of the facility.

The facility is used for working capital, general corporate purposes and to back-up our use of commercial paper. This facility requires our total indebtedness to be less than 62.5% of our total capitalization at the end of each fiscal quarter and our EBITDA (defined as net income plus interest, taxes, depreciation and amortization) to be at least two times our interest charges for the trailing four fiscal quarters at the end of each fiscal quarter. Failure to maintain these ratios will result in an event of default under the credit facility and will prohibit us from borrowing funds thereunder. As of March 31, 2012, we are in compliance with these ratios. Our total indebtedness is 50.2% of our total capitalization as of March 31, 2012 and our EBITDA is 4.8 times our interest charges. This credit

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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, 2012. However, $22.5 million was used to back up our outstanding commercial paper.

The principal amount of all series of first mortgage bonds outstanding at any one time under the EDE Mortgage is limited by terms of the mortgage to $1 billion. Substantially all of the property, plant and equipment of The Empire District Electric Company (but not its subsidiaries) is subject to the lien of the EDE Mortgage. Restrictions in the EDE mortgage bond indenture could affect our liquidity. The EDE Mortgage contains a requirement that for new first mortgage bonds to be issued, our net earnings (as defined in the EDE Mortgage) for any twelve consecutive months within the fifteen months preceding issuance must be two times the annual interest requirements (as defined in the EDE Mortgage) on all first mortgage bonds then outstanding and on the prospective issue of new first mortgage bonds. Our earnings for the twelve months ended March 31, 2012 would permit us to issue approximately $498.1 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, 2012, we had retired bonds and net property additions which would enable the issuance of at least $716.6 million principal amount of bonds if the annual interest requirements are met. As of March 31, 2012, 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, 2012, this test would allow us to issue approximately $11.0 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	Stable

*Not rated

On May 27, 2011 Standard & Poor’s revised our rating outlook to stable from positive after the May 22, 2011 tornado. On March 23, 2012, Standard & Poor’s reaffirmed our ratings. On May 26, 2011 after the May 22, 2011 tornado, and again on April 25, 2012, Moody’s reaffirmed all of our ratings. 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. On March 19, 2012, Fitch reaffirmed our 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.

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CONTRACTUAL OBLIGATIONS

Material changes to our contractual obligations at March 31, 2012, compared to December 31, 2011, consist of the following. On April 2, 2012, we agreed to issue up to $88 million principal amount of 3.58% First Mortgage Bonds, of which $38 million were issued on such date and are due on April 2, 2027. A second settlement of $50 million is anticipated to occur on or about June 1, 2012. The proceeds from the first settlement and funds from our line of credit were used to redeem all $74.8 million of our First Mortgage Bonds due 2024, and $13.2 million of our First Mortgage Bonds, Pollution Control Series which were due 2013. See Financing Activities above for details.

DIVIDENDS

In response to the expected loss of revenues resulting from the May 22, 2011 tornado, our level of retained earnings and other relevant factors, our Board of Directors suspended our quarterly dividend for the third and fourth quarters of 2011. On February 2, 2012, the Board of Directors re-established the dividend and declared a quarterly dividend of $0.25 per share on common stock payable on March 15, 2012 to holders of record as of March 1, 2012.

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, 2012, our retained earnings balance was $33.0 million, compared to $4.1 million as of March 31, 2011 and $33.7 million as of December 31, 2011, after paying out $10.5 million in dividends during the first quarter of 2012. On April 26, 2012, the Board of Directors declared a quarterly dividend of $0.25 per share on common stock payable June 15, 2012 to holders of record as of June 1, 2012.

Our diluted earnings per share were $0.23 for the quarter ended March 31, 2012 and were $1.31 and $1.17 for the years ended December 31, 2011 and 2010, respectively. Dividends paid per share were $0.25 for the three months ended March 31, 2012, $0.64 for the year ended December 31, 2011 and $1.28 for the year ended December 31, 2010.

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 June 9, 2011, we amended the EDE Mortgage in order to provide us with additional flexibility to pay dividends to our shareholders by permitting the payment of any dividend or distribution on, or purchase of, shares of its common stock within 60 days after the related date of declaration or notice of such dividend, distribution or purchase if (i) on the date of declaration or notice, such dividend, distribution or purchase would have complied

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with the provisions of the EDE Mortgage and (ii) as of the last day of the calendar month ended immediately preceding the date of such payment, our ratio of total indebtedness to total capitalization (after giving pro forma effect to the payment of such dividend, distribution, or purchase) was not more than 0.625 to 1.

OFF-BALANCE SHEET ARRANGEMENTS

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

CRITICAL ACCOUNTING POLICIES

See “Item 7 — 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, 2011 for a discussion of additional critical accounting policies. There were no changes in these policies in the quarter ended March 31, 2012.

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 65.0% of our 2011 generation fuel supply need through coal. Approximately 94% of our 2011 coal supply was Western coal. We have contracts and binding proposals to supply a portion of the fuel for our coal plants through 2014. These contracts satisfy approximately 100% of our anticipated fuel requirements for 2012, 61% for 2013 and 43% 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

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costs to avoid volatile natural gas prices. We enter into physical forward and financial derivative contracts with counterparties relating to our future natural gas requirements that lock in prices (with respect to predetermined percentages of our expected future natural gas needs) in an attempt to lessen the volatility in our fuel expenditures and improve predictability. As of March 31, 2012, 66%, or 3.2 million Dths’s, of our anticipated volume of natural gas usage for our electric operations for the remainder of 2012 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, 2012, our natural gas cost would increase by approximately $0.7 million based on our March 31, 2012 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, 2012, we have 0.8 million Dths in storage on the three pipelines that serve our customers. This represents 37% 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, 2012 (in thousands). However, due to purchased natural gas cost recovery mechanisms for our retail customers, fluctuations in the cost of natural gas have little effect on income.

Season	Minimum % Hedged	Dth Hedged – Financial	Dth Hedged – Physical	Dth in Storage	Actual % Hedged
Current	50%	780,000	81,770	756,565	48	%
Second	Up to 50%	100,000	—	—	2	%
Third	Up to 20%	—	—	—	—
Total		880,000	81,770	756,565

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, 2012 and December 31, 2011. There were no margin deposit liabilities at these dates.

(in millions)	March 31, 2012		December 31, 2011
Margin deposit assets	$	7.3	$	5.8

Our exposure to credit risk is concentrated primarily within our fuel procurement process, as we transact with a small 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, 2012, 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.

48

(in millions)
Net unrealized mark-to-market losses for physical forward natural gas contracts	$	15.4
Net unrealized mark-to-market losses for financial natural gas contracts	12.2
Net credit exposure	$	27.6

The $12.2 million net unrealized mark-to-market loss for financial natural gas contracts is comprised of $12.2 million that our counterparties are exposed to Empire for unrealized losses. 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, 2012, we have $7.3 million on deposit for NYMEX contract exposure to Empire, of which $7.2 million represents our collateral requirement. In addition, if NYMEX gas prices decreased 25% from their March 31, 2012 levels, we would be required to post an additional $2.0 million in collateral. If these prices increased 25%, our collateral requirement would decrease $2.1 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 2012 than in 2011, our interest expense would increase, and income before taxes would decrease by less than $0.2 million. This amount has been determined by considering the impact of the hypothetical interest rates on our highest month-end commercial paper balance for 2011. 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, 2012.

There have been no changes in our internal control over financial reporting that occurred during the first quarter of 2012 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

49

PART II.  OTHER INFORMATION

Item 1.  Legal Proceedings

See Note 7 of “Notes to Consolidated Financial Statements (Unaudited)” under “Legal Proceedings”, which description is incorporated herein by reference

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, 2011.

Item 5.  Other Information.

For the twelve months ended March 31, 2012, our ratio of earnings to fixed charges was 2.76x.  See Exhibit (12) hereto.

Item 6.  Exhibits.

(a)           Exhibits.

4)(a) Bond Purchase Agreement, dated as of April 2, 2012, by and among the Company and the Purchasers named therein. (Incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K dated April 2, 2012 and filed April 2, 2012, File No. 001-03368).

(4)(b) Thirty-Eighth Supplemental Indenture, dated April 2, 2012, to the Indenture of Mortgage and Deed of Trust dated as of September 1, 1944, as amended and supplemented, by and among the Company, The Bank of New York Mellon Trust Company, N.A. and UMB Bank & Trust, N. A. (Incorporated by reference to Exhibit 4.2 to Current Report on Form 8-K dated April 2, 2012 and filed April 2, 2012, File No. 001-03368).

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

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

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

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

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

(101) The following financial information from The Empire District Electric Company’s Quarterly Report on Form 10-Q for the period ended March 31, 2012, filed with the SEC on May 9, 2012, formatted in Extensible Business Reporting Language (XBRL): (i) the Consolidated Statements of Income for the three and twelve month periods ended March 31, 2012 and 2011, (ii) the Consolidated Balance Sheets at March 31, 2012 and December 31, 2011, (iii) the Consolidated Statements of Cash Flows for the three-month periods ended March 31, 2012 and 2011, and (iv) Notes to Consolidated Financial Statements.**

50

*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.

51

SIGNATURES

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

	THE EMPIRE DISTRICT ELECTRIC COMPANY
		Registrant
	By	/s/ Laurie A. Delano
		Laurie A. Delano
		Vice President — Finance and Chief Financial Officer
	By	/s/ Robert W. Sager
		Robert W. Sager
		Controller, Assistant Secretary and Assistant Treasurer
May 7, 2012

52

EX-12

EXHIBIT (12)

COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES

	Twelve
	Months Ended
	March 31, 2012
Income before provision for income taxes and fixed charges (Note A)	$	135,011,688
Fixed charges:
Interest on long-term debt	$	42,602,300
Interest on short-term debt	85,221
Other interest	62,946
Rental expense representative of an interest factor (Note B)	6,154,887
Total fixed charges	$	48,905,354
Ratio of earnings to fixed charges	2.76X

NOTE A:For the purpose of determining earnings in the calculation of the ratio, net income has been increased by the provision for income taxes, non-operating income taxes and by the sum of fixed charges as shown above.

NOTE B:One-third of rental expense (which approximates the interest factor).

EX-31.A

Exhibit (31)(a)

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

PURSUANT TO SECTION 302 OF THE

SARBANES-OXLEY ACT OF 2002

I, Bradley P. Beecher, certify that:

1.  I have reviewed this quarterly report on Form 10-Q of The Empire District Electric Company;

2.  Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.  Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.  The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.  The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting, which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 7, 2012

By:	/s/ Bradley P. Beecher
	Name: Bradley P. Beecher
	Title: President and Chief Executive Officer

EX-31.B

Exhibit (31)(b)

CERTIFICATION OF CHIEF FINANCIAL OFFICER

PURSUANT TO SECTION 302 OF THE

SARBANES-OXLEY ACT OF 2002

I, Laurie A. Delano, certify that:

1.  I have reviewed this quarterly report on Form 10-Q of The Empire District Electric Company;

2.  Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.  Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.  The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.  The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 7, 2012

By:	/s/ Laurie A. Delano
	Name: Laurie A. Delano
	Title: Vice President - Finance and Chief Financial Officer

EX-32.A

Exhibit (32)(a)

Certification Pursuant to 18 U.S.C. Section 1350,

As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

In connection with the Quarterly Report of The Empire District Electric Company (the “Company”) on Form 10-Q for the period ending March 31, 2012 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), Bradley P. Beecher, as Chief Executive Officer of the Company, certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1) The Report fully complies with the requirements of section 13(a) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Company.

By	/s/ Bradley P. Beecher
Name:	Bradley P. Beecher
Title:	President and Chief Executive Officer

Date:  May 7, 2012

A signed original of this written statement required by Section 906 or other document authenticating, acknowledging or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to The Empire District Electric Company and will be retained by The Empire District Electric Company and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.B

Exhibit (32)(b)

Certification Pursuant to 18 U.S.C. Section 1350,

As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

In connection with the Quarterly Report of The Empire District Electric Company (the “Company”) on Form 10-Q for the period ending March 31, 2012 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), Laurie A. Delano, as Chief Financial Officer of the Company, certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1) The Report fully complies with the requirements of section 13(a) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Company.

By	/s/ Laurie A. Delano
Name:	Laurie A. Delano
Title:	Vice President - Finance and Chief Financial Officer

Date:  May 7, 2012

A signed original of this written statement required by Section 906 or other document authenticating, acknowledging or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to The Empire District Electric Company and will be retained by The Empire District Electric Company and furnished to the Securities and Exchange Commission or its staff upon request.

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Commitments and Contingencies (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		85 Months Ended	3 Months Ended	12 Months Ended		3 Months Ended			1 Months Ended		3 Months Ended
	Mar. 31, 2012 plaintiff MW	Mar. 31, 2012 Elk River Windfarm MW	Dec. 31, 2012 Elk River Windfarm Y	Mar. 31, 2012 Southern Star Central Pipeline, Inc. Electric	Mar. 31, 2012 Southern Star Central Pipeline, Inc. Electric dth	Mar. 31, 2012 Iatan	Mar. 31, 2012 Physical gas and transportation contracts	Mar. 31, 2012 Coal and coal transportation contracts	Mar. 31, 2012 Purchased power Plum Point Energy Station Y MW	Dec. 31, 2008 Purchased power Cloud County Windfarm Y	Dec. 31, 2005 Purchased power Cloud County Windfarm Y	Mar. 31, 2012 Purchased power Cloud County Windfarm MW	Mar. 31, 2012 New construction	Mar. 31, 2012 New construction	Mar. 31, 2012 Leases Electric train	Mar. 31, 2012 Leases Gas office	Mar. 31, 2012 Leases Plum Point Energy Station railcar
Commitments and Contingencies
Amount of total power capacity of generating facility (in megawatts)	18
Proportionate ownership interest (as a percent)						12.00%
April 1, 2012 through December 31, 2012							$ 25.5	$ 26.7
January 1, 2013 through December 31, 2014							45.7	46.3
January 1, 2015 through December 31, 2016							24.5	31.4
January 1, 2017 and beyond							17.8
Term of long-term contract agreement (in years)			20						30
Agreement to purchase firm gas storage capacity (in Dths)					1,000,000
Term of long-term contract agreement (in years)					5 years
Amount of annual storage capacity reservation				1.1
Amount of long-term contract obligation									32.7
Amount of energy generated (in megawatts)		150							665			105
Amount of energy capacity under option to purchase (in megawatts)									50
Period of the average cost that is used as a basis for determining the maximum annual payments (in years)										20	20
Initial construction costs														7.9
Generating facility costs incurred through the period excluding AFUDC													$ 9.2	$ 7.9
Number of unit trains under short-term operating leases															2
Number of office facilities under short-term operating leases																1
Number of railcars under capital leases																	108
Number of plaintiffs	3

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Income Taxes (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		12 Months Ended
	Mar. 31, 2012	Mar. 31, 2011	Mar. 31, 2012	Dec. 31, 2011 Y	Mar. 31, 2011	Dec. 31, 2010
Income Taxes
Consolidated provision for income taxes	$ 6.2	$ 7.3	$ 33.3		$ 27.8
Consolidated effective federal and state income tax rates (as a percent)	38.70%	37.80%	38.60%		35.40%
Amount received from Southwest Power Administration (SWPA) as reimbursement towards estimated future lifetime replacement cost of the electrical energy and capacity lost due						26.6
Increase in current tax liability on recognition of taxable income						10.0
Payment for which recognition is deferred for tax purposes as per agreement with the IRS				26.1
Number of years payment be deferred for tax purposes will be recognized				50
Interest or penalties related to unrecognized tax benefits				$ 0		$ 0.1

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Risk Management and Derivative Financial Instruments (Details 3) (Electric)	3 Months Ended
	Mar. 31, 2012 Dth PerDth
Natural Gas Usage - Remainder 2012
Volumes and percentage of anticipated volume of natural gas usage
% Hedged (as a percent)	66.00%
Physical	2,111,000
Financial	1,110,000
Average Price (in dollars per dth)	6.363
Minimum Percentage Hedged for Electric Segment
End of Year Minimum % Hedged (as a percent)	66.00%
Natural Gas Usage - 2013
Volumes and percentage of anticipated volume of natural gas usage
% Hedged (as a percent)	44.00%
Physical	2,020,000
Financial	1,440,000
Average Price (in dollars per dth)	6.079
Minimum Percentage Hedged for Electric Segment
End of Year Minimum % Hedged (as a percent)	44.00%
Natural Gas Usage - 2014
Volumes and percentage of anticipated volume of natural gas usage
% Hedged (as a percent)	20.00%
Physical	460,000
Financial	1,240,000
Average Price (in dollars per dth)	5.514
Minimum Percentage Hedged for Electric Segment
End of Year Minimum % Hedged (as a percent)	20.00%
Natural Gas Usage - 2015
Volumes and percentage of anticipated volume of natural gas usage
% Hedged (as a percent)	11.00%
Financial	1,010,000
Average Price (in dollars per dth)	5.439
Minimum Percentage Hedged for Electric Segment
End of Year Minimum % Hedged (as a percent)	11.00%
Current Year Procurement Guidelines
Volumes and percentage of anticipated volume of natural gas usage
% Hedged (as a percent)	100.00%
Procurement guidelines
Maximum flexibility to hedge any future year's expected requirements (as a percent)	80.00%
Maximum percentage of volume to be hedged in any given month	100.00%
Minimum Percentage Hedged for Electric Segment
End of Year Minimum % Hedged (as a percent)	100.00%
First Year Procurement Guidelines
Volumes and percentage of anticipated volume of natural gas usage
% Hedged (as a percent)	60.00%
Minimum Percentage Hedged for Electric Segment
End of Year Minimum % Hedged (as a percent)	60.00%
Second Year Procurement Guidelines
Volumes and percentage of anticipated volume of natural gas usage
% Hedged (as a percent)	40.00%
Minimum Percentage Hedged for Electric Segment
End of Year Minimum % Hedged (as a percent)	40.00%
Third Year Procurement Guidelines
Volumes and percentage of anticipated volume of natural gas usage
% Hedged (as a percent)	20.00%
Minimum Percentage Hedged for Electric Segment
End of Year Minimum % Hedged (as a percent)	20.00%
Fourth Year Procurement Guidelines
Volumes and percentage of anticipated volume of natural gas usage
% Hedged (as a percent)	10.00%
Minimum Percentage Hedged for Electric Segment
End of Year Minimum % Hedged (as a percent)	10.00%

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Regulated Operating Expense (Tables)

3 Months Ended

Mar. 31, 2012

Regulated Operating Expense

Schedule of regulated operating expenses

	Three Months Ended		Three Months Ended		Twelve Months Ended		Twelve Months Ended
	2012		2011		2012		2011
Electric transmission and distribution expense	$	4,108	$	3,823	$	15,647	$	13,992
Natural gas transmission and distribution expense	652		562		2,476		2,225
Power operation expense (other than fuel)	3,794		2,677		14,394		11,129
Customer accounts and assistance expense	2,434		2,536		10,108		11,234
Employee pension expense (1)	2,536		1,844		9,496		6,279
Employee healthcare plan (1)	2,238		1,621		8,056		7,001
General office supplies and expense	2,752		2,898		10,011		11,807
Administrative and general expense	4,219		3,647		14,868		13,126
Allowance for uncollectible accounts	593		82		3,935		3,133
Miscellaneous expense	22		25		84		164
Total	$	23,348	$	19,715	$	89,075	$	80,090

(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, Kansas and Oklahoma jurisdictions.

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Stock-Based Awards and Programs (Details) (USD $)	3 Months Ended		12 Months Ended		3 Months Ended									12 Months Ended
	Mar. 31, 2012	Mar. 31, 2011	Mar. 31, 2012	Mar. 31, 2011	Mar. 31, 2012 Performance-Based Restricted Stock Awards Y	Mar. 31, 2011 Performance-Based Restricted Stock Awards Y	Mar. 31, 2012 Performance-Based Restricted Stock Awards Minimum	Mar. 31, 2011 Performance-Based Restricted Stock Awards Minimum	Mar. 31, 2012 Performance-Based Restricted Stock Awards Maximum	Mar. 31, 2011 Performance-Based Restricted Stock Awards Maximum	Mar. 31, 2012 Stock Options M	Mar. 31, 2011 Stock Options M	Mar. 31, 2012 Time-Vested Restricted Stock Awards	Dec. 31, 2011 Time-Vested Restricted Stock Awards M	Mar. 31, 2011 Time-Vested Restricted Stock Awards
Stock-Based Awards and Programs
Compensation expense	$ 822,000	$ 741,000	$ 1,846,000	$ 3,136,000
Tax benefit recognized	298,000	271,000	642,000	1,143,000
Assumptions used in the model for each grant year
Risk-free interest rate, low end of range (as a percent)					0.16%	0.61%					0.17%	0.45%
Risk-free interest rate, high end of range (as a percent)					0.45%	1.15%					0.83%	2.39%
Expected volatility (as a percent)					21.50%	26.10%					25.00%	23.00%
Expected volatility of peer group stock (as a percent)							13.50%	21.10%	51.90%	82.20%
Expected dividend yield on Empire stock (as a percent)					4.90%	6.30%					4.90%	6.30%
Expected forfeiture rates (as a percent)					3.00%	3.00%
Plan cycle (in years)					3	3
Fair value percentage							41.00%	97.00%	104.00%	143.00%
Expected life (in months)											78	78
Weighted average fair value per share (in dollars per share)					$ 13.63	$ 27.20
Market value (in dollars per share)											$ 20.35	$ 21.79
Weighted average fair value per option (in dollars per share)											$ 1.56	$ 1.94
Changes in restricted stock awards
Nonvested, balance at the beginning of the period (in shares)					37,400	47,500							3,433
Granted (in shares)					10,000	10,900								10,200
Awarded (in shares)					(7,823)	(39,621)								(794)
Awarded in excess of target (in shares)						18,621
Not Awarded (in shares)					(5,677)
Distributed (in shares)													133	661
Forfeited (in shares)														6,106
Vested but not distributed (in shares)														133
Nonvested, balance at the end of the period (in shares)					33,900	37,400							3,300	3,433
Weighted Average Grant Date Price
Nonvested, balance at the beginning of the period (in dollars per share)					$ 19.28	$ 19.86							$ 21.84		$ 21.84
Granted (in dollars per share)					$ 20.97	$ 21.84								$ 21.84
Awarded (in dollars per share)					$ 18.12	$ 21.92								$ 19.32
Awarded in Excess of Target (in dollars per share)						$ 21.92
Not Awarded (in dollars per share)					$ 18.12
Distributed/Awarded (in dollars per share)													$ 20.13	$ 21.02
Vested but not distributed (in dollars per share)														$ 20.13
Nonvested, balance at the end of the period (in dollars per share)					$ 20.25	$ 19.28							$ 20.35	$ 21.84	$ 21.84
Unrecognized compensation cost related to estimated outstanding awards					$ 200,000
Period from date of termination of employment due to death, retirement or disability during which the pro-rata portion of the awards are distributed (in months)														6
Vesting period (in years)														3 years

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Financing (Details) (USD $)	3 Months Ended								1 Months Ended	6 Months Ended
	Mar. 31, 2012 First mortgage bonds EDE	Mar. 31, 2012 7.0% Series due 2024	Mar. 01, 2012 7.0% Series due 2024	Mar. 31, 2012 5.3% Pollution Control Series due 2013	Mar. 01, 2012 5.3% Pollution Control Series due 2013	Mar. 31, 2012 5.2% Pollution Control Series due 2013	Mar. 01, 2012 5.2% Pollution Control Series due 2013	Jun. 30, 2012 3.58% Series Due 2027	Apr. 30, 2012 3.58% Series Due 2027 Issuance of Debt [Member]	Jun. 30, 2012 3.58% Series Due 2027 Issuance of Debt [Member]
Financing
Interest rate, stated percentage		7.00%		5.30%		5.20%		3.58%
Amount called for redemption			$ 74,800,000		$ 8,000,000		$ 5,200,000
Aggregate principal amount of debt entered into in private placement									88,000,000
First settlement of bond issuance under private placement									38,000,000
Represents the amount of the June expected settlement in private placement offering										50,000,000
Maximum principal amount outstanding at any one time	$ 1,000,000,000

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Regulatory Matters

3 Months Ended

Mar. 31, 2012

Regulatory Matters

Regulatory Matters

Note 3— Regulatory Matters

The Missouri Public Service Commission (MPSC) approved a joint settlement agreement allowing us to defer actual incremental operating and maintenance expenses associated with the repair, restoration and rebuilding activities resulting from the tornado which hit our service territory on May 22, 2011. In addition, depreciation related to the capital expenditures will be deferred and a carrying charge will be accrued. These amounts, which were approximately $2.0 million as of March 31, 2012, have been recorded as a regulatory asset.

As part of a stipulated agreement in our 2009 Kansas rate case, approved by the KCC on June 25, 2010, we also deferred depreciation and operating and maintenance expense on both Plum Point and Iatan 2 from their respective in-service dates until the effective date for rates from the next Kansas case, which was January 1, 2012. These deferrals will be recovered over a 4 year period.

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

Regulatory Assets and Liabilities

	March 31, 2012		December 31, 2011
Regulatory Assets:
Under recovered purchased gas costs — gas segment - current	$	224	$	211
Under recovered electric fuel and purchased power costs — current	3,661		7,513
Regulatory assets, current(1)	3,885		7,724
Pension and other postretirement benefits(2)	118,417		121,058
Income taxes	49,330		49,631
Deferred construction accounting costs(3)	17,087		17,095
Unamortized loss on reacquired debt	11,333		11,610
Unsettled derivative losses — electric segment	10,117		7,839
System reliability — vegetation management	7,218		6,569
Storm costs(4)	5,025		5,303
Asset retirement obligation	4,568		3,571
Customer programs	3,718		3,408
Unamortized loss on interest rate derivative	1,383		1,462
Other	696		1,420
Under recovered purchased gas costs — gas segment	627		1,281
Deferred operating and maintenance expense	1,676		1,444
Under recovered electric fuel and purchased power costs	233		231
Regulatory assets, long-term	231,428		231,922
Total Regulatory Assets	$	235,313	$	239,646

	March 31, 2012		December 31, 2011
Regulatory Liabilities:
Costs of removal	75,923		73,562
SWPA payment for Ozark Beach lost generation	24,418		25,074
Income taxes	12,270		12,337
Deferred construction accounting costs — fuel(3)	8,266		8,304
Unamortized gain on interest rate derivative	3,669		3,711
Pension and other postretirement benefits(5)	2,675		2,939
Over recovered electric fuel and purchased power costs	4,446		2,513
Other	—		—
Regulatory liabilities, long-term	131,667		128,440
Total Regulatory Liabilities	$	131,667	$	128,440

(1)  Reflects over and under recovered costs expected to be returned or recovered, as applicable, within the next 12 months in Missouri, Kansas and Oklahoma rates.

(2) Primarily reflects regulatory assets resulting from the unfunded portion of our pension and OPEB liabilities and regulatory accounting for EDG acquisition costs. Approximately $0.1 million in pension and other postretirement benefit costs have been recognized since January 1, 2012 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)  Reflects the deferral of depreciation, operations and maintenance and carrying costs relating to Iatan 1 and Iatan 2 in accordance with our 2005 regulatory plan, as well as Plum Point construction costs incurred subsequent to February 28, 2010. All of these deferrals ended when recovery in rates began and these costs are now being amortized over the life of the plants. The regulatory plan also required us to continue to defer the fuel and purchased power expense impacts of Iatan 2, which are recorded in Non-Current Regulatory Liabilities.

Balances as of March 31, 2012	Deferred Carrying Charges		Deferred O&M	Depreciation	Total
Iatan 1	$	2,715	1,358	1,645	$	5,718
Iatan 2	$	3,873	4,279	2,718	$	10,870
Plum Point	$	65	276	158	$	499
Total					$	17,087

Balances as of December 31, 2011	Deferred Carrying Charges		Deferred O&M	Depreciation	Total
Iatan 1	$	2,728	1,363	1,652	$	5,743
Iatan 2	$	3,891	4,271	2,728	$	10,890
Plum Point	$	65	239	158	$	462
Total					$	17,095

(4)  Reflects ice storm costs incurred in 2007 and costs incurred as a result of the May 2011 tornado.

(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, 2012, regulatory liabilities and corresponding expenses have been reduced by less than $0.1 million as a result of ratemaking treatment.

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Stock-Based Awards and Programs (Details 2) (Stock Options, USD $) In Millions, except Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2012 Y	Mar. 31, 2011 Y
Stock options
Outstanding, balance at the beginning of the period (in shares)	190,300	267,400
Exercised (in shares)	(27,000)
Outstanding, balance at the end of the period (in shares)	163,300	267,400
Exercisable (in shares)	128,500	205,600
Weighted Average Exercise Price
Outstanding, balance at the beginning of the period (in dollars per option)	$ 21.56	$ 21.69
Exercised (in dollars per share)	$ 18.12
Outstanding, balance at the end of the period (in dollars per option)	$ 22.13	$ 21.69
Exercisable (in dollars per share)	$ 23.15	$ 22.73
Aggregate intrinsic value
Aggregate intrinsic value of unexercised options		$ 0.2
Weighted-average remaining contractual life of outstanding options (in years)	3.9	5.8
Range of exercise prices, low end of range (in dollars per share)	$ 18.36	$ 18.12
Range of exercise prices, high end of range (in dollars per share)	$ 23.81	$ 23.81
Total unrecognized compensation expense related to non-vested options and related dividend equivalents granted under the plan		0.1
Recognition period, low end of range (in years)		1
Recognition period, high end of range (in years)		2
Maximum
Aggregate intrinsic value
Aggregate intrinsic value of unexercised options	0.1
Total unrecognized compensation expense related to non-vested options and related dividend equivalents granted under the plan	$ 0.1
Recognition period	1

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Regulatory Matters (Details) (USD $)																				3 Months Ended																									1 Months Ended
	Mar. 31, 2012	Dec. 31, 2011	Mar. 31, 2012 Missouri jurisdictional portion of the payment, net of tax	Mar. 31, 2012 Over recovered electric fuel and purchased power costs	Dec. 31, 2011 Over recovered electric fuel and purchased power costs	Mar. 31, 2012 Cost of removal	Dec. 31, 2011 Cost of removal	Mar. 31, 2012 Income taxes	Dec. 31, 2011 Income taxes	Mar. 31, 2012 Unamortized gain on interest rate derivative	Dec. 31, 2011 Unamortized gain on interest rate derivative	Mar. 31, 2012 Pension and other postretirement benefits	Dec. 31, 2011 Pension and other postretirement benefits	Mar. 31, 2012 Deferred construction accounting costs - fuel	Dec. 31, 2011 Deferred construction accounting costs - fuel	Mar. 31, 2012 SWPA payment for Ozark Beach lost generation	Dec. 31, 2011 SWPA payment for Ozark Beach lost generation	Mar. 31, 2012 Under recovered electric fuel and purchased power costs	Dec. 31, 2011 Under recovered electric fuel and purchased power costs	Mar. 31, 2012 Under recovered electric fuel and purchased power costs Missouri, Kansas and Oklahoma M	Mar. 31, 2012 Pension and other postretirement benefits	Dec. 31, 2011 Pension and other postretirement benefits	Mar. 31, 2012 Income taxes	Dec. 31, 2011 Income taxes	Mar. 31, 2012 Storm costs	Dec. 31, 2011 Storm costs	Mar. 31, 2012 Unamortized loss on reacquired debt	Dec. 31, 2011 Unamortized loss on reacquired debt	Mar. 31, 2012 Deferred operating and maintenance expenses	Dec. 31, 2011 Deferred operating and maintenance expenses	Mar. 31, 2012 Unamortized loss on interest rate derivative	Dec. 31, 2011 Unamortized loss on interest rate derivative	Mar. 31, 2012 Asset retirement obligation:	Dec. 31, 2011 Asset retirement obligation:	Mar. 31, 2012 Customer programs	Dec. 31, 2011 Customer programs	Mar. 31, 2012 System reliability - vegetation management	Dec. 31, 2011 System reliability - vegetation management	Mar. 31, 2012 Other:	Dec. 31, 2011 Other:	Mar. 31, 2012 Deferred construction accounting costs.	Dec. 31, 2011 Deferred construction accounting costs.	Mar. 31, 2012 Gas Under recovered purchased gas costs	Dec. 31, 2011 Gas Under recovered purchased gas costs	Jan. 31, 2012 Electric Kansas 2009 Rate Case Kansas Corporation Commission (KCC) Y	Mar. 31, 2012 Electric Unsettled derivative losses	Dec. 31, 2011 Electric Unsettled derivative losses
Regulatory Assets and Liabilities
Deferred depreciation, operations and maintenance, and carrying costs related to capital expenditure			$ 2,000,000
Period over which deferred depreciation, operating and maintenance expenses will be recovered (in years)																																													4
Regulatory Assets:
Regulatory assets, current	3,885,000	7,724,000																3,661,000	7,513,000																								224,000	211,000
Regulatory assets, long-term	231,428,000	231,922,000																233,000	231,000		118,417,000	121,058,000	49,330,000	49,631,000	5,025,000	5,303,000	11,333,000	11,610,000	1,676,000	1,444,000	1,383,000	1,462,000	4,568,000	3,571,000	3,718,000	3,408,000	7,218,000	6,569,000	696,000	1,420,000	17,087,000	17,095,000	627,000	1,281,000		10,117,000	7,839,000
Regulatory assets, total	235,313,000	239,646,000
Period to recover costs in Missouri rates (in months)																				12
Pension and other postretirement benefit costs recognized																					100,000
Regulatory Liabilities:
Regulatory liabilities, long-term	131,667,000	128,440,000		4,446,000	2,513,000	75,923,000	73,562,000	12,270,000	12,337,000	3,669,000	3,711,000	2,675,000	2,939,000	8,266,000	8,304,000	24,418,000	25,074,000
Regulatory liabilities, total	131,667,000	128,440,000
Pension and other postretirement benefit costs reduction recognized																					$ 100,000

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Summary of Significant Accounting Policies (Details)	3 Months Ended
	Mar. 31, 2012 town segment
Summary of Significant Accounting Policies
Number of business segments	3
Number of towns to which water service is provided	3

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Regulated Operating Expense (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		12 Months Ended
	Mar. 31, 2012	Mar. 31, 2011	Mar. 31, 2012	Mar. 31, 2011
Regulated Operating Expense
Electric transmission and distribution expense	$ 4,108	$ 3,823	$ 15,647	$ 13,992
Natural gas transmission and distribution expense	652	562	2,476	2,225
Power operation expense (other than fuel)	3,794	2,677	14,394	11,129
Customer accounts & assistance expense	2,434	2,536	10,108	11,234
Employee pension expense	2,536	1,844	9,496	6,279
Employee healthcare plan	2,238	1,621	8,056	7,001
General office supplies and expense	2,752	2,898	10,011	11,807
Administrative and general expense	4,219	3,647	14,868	13,126
Allowance for uncollectible accounts	593	82	3,935	3,133
Miscellaneous expense	22	25	84	164
TOTAL	$ 23,348	$ 19,715	$ 89,075	$ 80,090

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Regulatory Matters (Details 2) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2012	Dec. 31, 2011
Regulatory Assets
Deferred construction accounting costs	$ 17,087	$ 17,095
Iatan1
Regulatory Assets
Deferred construction accounting costs	5,718	5,743
Iatan1 | Deferred Carrying Charges
Regulatory Assets
Deferred construction accounting costs	2,715	2,728
Iatan1 | Deferred O&M
Regulatory Assets
Deferred construction accounting costs	1,358	1,363
Iatan1 | Depreciation.
Regulatory Assets
Deferred construction accounting costs	1,645	1,652
Iatan2
Regulatory Assets
Deferred construction accounting costs	10,870	10,890
Iatan2 | Deferred Carrying Charges
Regulatory Assets
Deferred construction accounting costs	3,873	3,891
Iatan2 | Deferred O&M
Regulatory Assets
Deferred construction accounting costs	4,279	4,271
Iatan2 | Depreciation.
Regulatory Assets
Deferred construction accounting costs	2,718	2,728
Plum point
Regulatory Assets
Deferred construction accounting costs	499	462
Plum point | Deferred Carrying Charges
Regulatory Assets
Deferred construction accounting costs	65	65
Plum point | Deferred O&M
Regulatory Assets
Deferred construction accounting costs	276	239
Plum point | Depreciation.
Regulatory Assets
Deferred construction accounting costs	$ 158	$ 158

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Risk Management and Derivative Financial Instruments (Details) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2012	Dec. 31, 2011
Fair value of derivative financial instruments
Total derivatives assets	$ 12	$ 2
Current liabilities	6,171	4,769
Non-current liabilities and deferred credits	6,028	5,081
Total derivatives liabilities	12,199	9,850
Non-designated as hedging instruments due to regulatory accounting | Commodity contracts
Fair value of derivative financial instruments
Non-current assets and deferred charges- Other	12	2
Non-designated as hedging instruments due to regulatory accounting | Commodity contracts | Gas
Fair value of derivative financial instruments
Current liabilities	1,097	967
Non-current liabilities and deferred credits	3	86
Non-designated as hedging instruments due to regulatory accounting | Commodity contracts | Electric
Fair value of derivative financial instruments
Current liabilities	5,074	3,802
Non-current liabilities and deferred credits	$ 6,025	$ 4,995

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Recently Issued and Proposed Accounting Standards

3 Months Ended

Mar. 31, 2012

Recently Issued and Proposed Accounting Standards

Recently Issued and Proposed Accounting Standards

Note 2 - Recently Issued and Proposed Accounting Standards

Balance Sheet Offsetting:  In December 2011, the FASB amended the guidance governing the offsetting, or netting, of assets and liabilities on the balance sheet.  Under the revised guidance, an entity would be required to disclose both the gross and net information about instruments and transactions that are eligible for offset on the balance sheet, as well as instruments or transactions subject to a master netting agreement.  This standard is effective for annual periods beginning after January 1, 2013.  The application of this standard will not have a material impact on our results of operations, financial position or liquidity.

See Note 1 under “Notes to Consolidated Financial Statements” in our Annual Report on Form 10-K for the year ended December 31, 2011 for further information regarding recently issued and proposed accounting standards.

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Risk Management and Derivative Financial Instruments (Details 2) (USD $)	3 Months Ended		12 Months Ended
	Mar. 31, 2012	Mar. 31, 2011	Mar. 31, 2012	Mar. 31, 2011
Electric
Gain / (Loss) on derivatives
Unrealized losses applicable to financial instruments which will settle in next twelve months	$ 5,100,000		$ 5,100,000
Period within which financial instruments will settle (in months)	12 months		12 months
Amount of Gain / (Loss) on Derivative recognized as Regulatory (assets)/Liabilities	(2,302,000)	632,000	(9,899,000)	(2,037,000)
Amount of Gain / (Loss) Recognized in Income on Derivative	(24,000)	160,000	(2,416,000)	(592,000)
Gas
Gain / (Loss) on derivatives
Amount of Gain / (Loss) on Derivative recognized as Regulatory (assets)/Liabilities	(655,000)	(96,000)	(2,475,000)	(595,000)
Commodity contracts | Electric
Gain / (Loss) on derivatives
Amount of Gain / (Loss) on Derivative recognized as Regulatory (assets)/Liabilities	(2,302,000)	632,000	(9,899,000)	(2,037,000)
Amount of Gain / (Loss) Recognized in Income on Derivative	(24,000)	160,000	(2,416,000)	(592,000)
Commodity contracts | Gas
Gain / (Loss) on derivatives
Amount of Gain / (Loss) on Derivative recognized as Regulatory (assets)/Liabilities	(655,000)	(96,000)	(2,475,000)	(595,000)
Derivatives in Cash Flow Hedging Relationships | Electric
Gain / (Loss) on derivatives
Amount of Loss Reclassed from OCI into Income (Effective portion)				(5,814,000)
Amount of Loss Recognized in OCI on Derivative (Effective portion)				(361,000)
Derivatives in Cash Flow Hedging Relationships | Commodity contracts | Electric
Gain / (Loss) on derivatives
Amount of Loss Reclassed from OCI into Income (Effective portion)				(5,814,000)
Amount of Loss Recognized in OCI on Derivative (Effective portion)				$ (361,000)

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Commitments and Contingencies (Details 2) (USD $) In Millions, unless otherwise specified	1 Months Ended	3 Months Ended							3 Months Ended									1 Months Ended	3 Months Ended		1 Months Ended
	Jun. 30, 2006 Gas site	Mar. 31, 2012 Gas	Mar. 31, 2012 Permits Electric Y	Mar. 31, 2012 SO2 Emissions Electric T	Mar. 31, 2012 Clean Air Interstate Rule Electric state allowancePerTon MW	Mar. 31, 2012 NAAQS Electric ppb Y	Jan. 06, 2010 NAAQS Electric Minimum ppb	Jan. 06, 2010 NAAQS Electric Maximum ppb	Mar. 31, 2012 Power Plant Mercury And Air Toxics Rule Electric phase	Mar. 31, 2012 Power Plant Mercury And Air Toxics Rule Electric Minimum	Mar. 31, 2012 Power Plant Mercury And Air Toxics Rule Electric Maximum	Mar. 31, 2012 Surface Impoundments Electric option	Mar. 31, 2012 Surface Impoundments Iatan Electric	Mar. 31, 2012 Surface Impoundments Plum point Electric	Mar. 31, 2012 Green House Gases poundperMWh Y	Mar. 31, 2012 Green House Gases Minimum	Sep. 22, 2009 Green House Gases Electric T	Nov. 30, 2010 Renewable Energy Electric	Mar. 31, 2012 Renewable Energy Electric mWh certificate	Nov. 04, 2008 Renewable Energy Electric customer	Mar. 31, 2011 National Emission Standards for Hazardous Air Pollutants Electric Y
Environmental Laws And Regulations
Number of years site operating permits are valid			5
Expected cost of adding Carbon injection system										$ 112	$ 130
Period for compliance (in years)																					4
Amount of SO2 emission permitted under each SO2 allowance per affected unit (in tons)				1
Minimum capacity of power plant called to reduce emission levels of SO2 and NOx (in megawatts)					25
Number of states in which fossil-fueled power plants are required to reduce emission levels of SO2 and NOx as per CAIR					28
Ratio of S02 allowances that must be utilized numerator					2
Ratio of S02 allowances that must be utilized denominator					1
Percentage of SO2 reduction from 2005 levels by 2014, required by the proposed CATR					73.00%
Number of allowances per ton of SO2 emissions					1
Percentage of NOx reduction from 2005 levels by 2014, required by the proposed CATR					54.00%
Proposed primary standard							60	70
Normal reconsideration period for ozone standards (in years)						5
2008 standard at which states will continue to identify and designate all non-attainment areas						75
Phase-in period for proposed standards (in years)																					3
Number of phases expected to reduce nationwide mercury emissions									2
Minimum emission threshold of CO2e from power generating and certain other facilities requires to report Greenhouse Gases (in metric tons)																	25,000
Limit of CO2 emissions															1,000
Minimum threshold percentage of emission for coal-fired power plant																50.00%
Average period reqiure for emission of CO2 (in years)															30
Percentage of ownership in a coal ash impoundment at a generating facility													12.00%	7.52%
Number of options in the EPA proposal												2
Potential cost for construction of new landfill and conversion of existing ash handling from wet to dry system(s)												15
Minimum percentage of energy purchased through long-term Purchased Power Agreements																			15.00%
Amount of renewable energy certificates generated each year																			900,000
Represents the megawatt-hour of renewable energy per renewable energy certificate (REC)																			1
Minimum percentage of Missouri retail sales required to generate or purchase electricity by 2011																			2.00%	2.00%
Minimum percentage of Missouri retail sales required to generate or purchase electricity by 2021																			15.00%	15.00%
Number of customers who have challenged exemption from solar requirement																				2
Percentage of Missouri retail sales required to generate or purchase solar energy																			2.00%	2.00%
Percentage of Kansas retail customer peak capacity required to be sourced from renewable energy by 2011																		10.00%
Percentage of Kansas retail customer peak capacity required to be sourced from renewable energy by 2016																		15.00%
Percentage of Kansas retail customer peak capacity required to be sourced from renewable energy by 2020																		20.00%
Number of former manufactured plant sites with potential future remediation	2
Remediation costs		$ 0.2

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CONSOLIDATED STATEMENTS OF INCOME (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended		12 Months Ended
	Mar. 31, 2012	Mar. 31, 2011	Mar. 31, 2012	Mar. 31, 2011
Operating revenues:
Electric and water	$ 119,726	$ 128,360	$ 515,641	$ 499,042
Gas	15,683	20,989	41,124	47,314
Other	1,735	1,379	6,521	5,754
Total operating revenues	137,144	150,728	563,286	552,110
Operating revenue deductions:
Fuel and purchased power	45,229	54,217	191,268	202,831
Cost of natural gas sold and transported	8,581	12,040	19,302	23,545
Regulated operating expenses	23,348	19,715	89,075	80,090
Other operating expenses	598	475	2,221	1,937
Maintenance and repairs	9,124	9,242	40,923	38,206
Loss on plant disallowance			150
Depreciation and amortization	14,935	17,333	61,138	62,804
Provision for income taxes	6,084	7,269	32,886	27,850
Other taxes	8,435	8,589	30,426	28,582
Total operating revenue deductions	116,334	128,880	467,389	465,845
Operating income	20,810	21,848	95,897	86,265
Other income and (deductions):
Allowance for equity funds used during construction	50		343	2,797
Interest income	179	23	712	129
Benefit/(provision) for other income taxes	(115)	24	(366)	6
Other - non-operating expense, net	(227)	(285)	(1,224)	(1,077)
Total other income and (deductions)	(113)	(238)	(535)	1,855
Interest charges:
Long-term debt	10,654	10,633	42,603	42,107
Trust preferred securities				1,027
Short-term debt	30	31	85	417
Allowance for borrowed funds used during construction	(48)	(23)	(243)	(3,245)
Other	257	(953)	63	(2,918)
Total interest charges	10,893	9,688	42,508	37,388
Net income	$ 9,804	$ 11,922	$ 52,854	$ 50,732
Weighted average number of common shares outstanding - basic	42,047	41,665	41,946	41,300
Weighted average number of common shares outstanding - diluted	42,075	41,707	41,968	41,324
Total earnings per weighted average share of common stock - basic and diluted (in dollars per share)	$ 0.23	$ 0.29	$ 1.26	$ 1.23
Dividends declared per share of common stock (in dollars per share)	$ 0.25	$ 0.32	$ 0.57	$ 1.28

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Segment Information (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		12 Months Ended
	Mar. 31, 2012 town segment	Mar. 31, 2011	Mar. 31, 2012	Mar. 31, 2011	Dec. 31, 2011
Segment Information
Number of business segments	3
Number of towns to which water service is provided	3
Statement of Operations Information, balance sheet information and capital expenditures of business segments
Revenues	$ 137,144	$ 150,728	$ 563,286	$ 552,110
Depreciation and amortization	14,935	17,333	61,138	62,804
Federal and state income taxes	6,199	7,245	33,252	27,844
Operating income	20,810	21,848	95,897	86,265
Interest income	179	23	712	129
Interest expense	10,941	9,711	42,751	40,633
Income from AFUDC (debt and equity)	98	23	586	6,042
Net Income	9,804	11,922	52,854	50,732
Capital Expenditures	35,748	17,557	119,368	94,737
Total assets	2,026,459		2,026,459		2,021,835
Goodwill	39,492		39,492		39,492
Electric
Statement of Operations Information, balance sheet information and capital expenditures of business segments
Revenues	119,726	128,360	515,641	499,042
Depreciation and amortization	13,569	16,028	55,778	57,710
Federal and state income taxes	5,187	5,633	31,197	25,278
Operating income	18,243	18,276	88,557	78,319
Interest income	170	22	702	148
Interest expense	10,027	8,801	39,086	37,040
Income from AFUDC (debt and equity)	98	23	583	6,023
Net Income	8,173	9,301	49,542	46,564
Capital Expenditures	34,079	16,850	110,728	87,659
Total assets	1,940,782		1,940,782		1,931,320
Gas
Statement of Operations Information, balance sheet information and capital expenditures of business segments
Revenues	15,683	20,989	41,124	47,314
Depreciation and amortization	919	873	3,539	3,397
Federal and state income taxes	697	1,381	991	1,561
Operating income	2,054	3,195	5,374	6,287
Interest income	72	71	260	348
Interest expense	977	977	3,910	3,934
Income from AFUDC (debt and equity)			3	19
Net Income	1,119	2,246	1,582	2,534
Capital Expenditures	725	340	4,507	5,293
Total assets	146,331		146,331		145,897
Goodwill	39,492		39,492		39,492
Other.
Statement of Operations Information, balance sheet information and capital expenditures of business segments
Revenues	1,883	1,527	7,113	6,346
Depreciation and amortization	447	432	1,821	1,697
Federal and state income taxes	315	231	1,064	1,005
Operating income	513	377	1,966	1,659
Interest expense		3	5	26
Net Income	512	375	1,730	1,634
Capital Expenditures	944	367	4,133	1,785
Total assets	27,047		27,047		26,038
Eliminations
Statement of Operations Information, balance sheet information and capital expenditures of business segments
Revenues	(148)	(148)	(592)	(592)
Interest income	(63)	(70)	(250)	(367)
Interest expense	(63)	(70)	(250)	(367)
Total assets	$ (87,701)		$ (87,701)		$ (81,420)

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CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Operating activities:
Net income	$ 9,804	$ 11,922
Adjustments to reconcile net income to cash flows from operating activities:
Depreciation and amortization including regulatory items	20,846	22,796
Pension and other postretirement benefit costs, net of contributions	1,035	(11,768)
Deferred income taxes and unamortized investment tax credit, net	6,495	8,537
Allowance for equity funds used during construction	(50)
Stock compensation expense	871	867
Cash flows impacted by changes in:
Accounts receivable and accrued unbilled revenues	6,795	6,052
Fuel, materials and supplies	46	1,001
Prepaid expenses, other current assets and deferred charges	(1,281)	(4,070)
Accounts payable and accrued liabilities	(18,254)	(15,066)
Interest, taxes accrued and customer deposits	10,850	9,556
Accumulated provision - rate refunds		375
Other liabilities and other deferred credits	1,970	3,829
Net cash provided by operating activities	39,127	34,031
Investing activities:
Capital expenditures - regulated	(30,355)	(16,957)
Capital expenditures and other investments - non-regulated	(699)	(292)
Net cash used in investing activities	(31,054)	(17,249)
Financing activities:
Proceeds from issuance of common stock, net of issuance costs	2,230	3,073
Net short-term borrowings/(repayments)	10,500	(13,000)
Repayment of first mortgage bonds	(13,200)
Dividends	(10,514)	(13,337)
Other	(228)	(212)
Net cash used in financing activities	(11,212)	(23,476)
Net decrease in cash and cash equivalents	(3,139)	(6,694)
Cash and cash equivalents at beginning of period	5,408	14,499
Cash and cash equivalents at end of period	$ 2,269	$ 7,805

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Fair Value Measurements (Details) (Recurring basis, USD $) In Thousands, unless otherwise specified	Mar. 31, 2012	Dec. 31, 2011
Assets/(Liabilities) at Fair Value
Fair Value Measurements at Reporting Date
Net derivative liabilities	$ (12,187)	$ (9,848)
Quoted Prices in Active Markets for Identical Assets (Level 1)
Fair Value Measurements at Reporting Date
Net derivative liabilities	$ (12,187)	$ (9,848)

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Commitments and Contingencies (Tables)

3 Months Ended

Mar. 31, 2012

Commitments and Contingencies

Schedule of coal, natural gas and transportation contracts

(in millions)	Firm physical gas and transportation contracts		Coal and coal transportation contracts
April 1, 2012 through December 31, 2012	$	25.5	$	26.7
January 1, 2013 through December 31, 2014	45.7		46.3
January 1, 2015 through December 31, 2016	24.5		31.4
January 1, 2017 and beyond	17.8		—

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Fair Value Measurements (Details 2) (USD $) In Millions, unless otherwise specified	Mar. 31, 2012
Long-Term Debt
Carrying amount of total debt exclusive of capital leases	$ 674.8
Fair market value	$ 726.7

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Stock-Based Awards and Programs (Tables)

3 Months Ended

Mar. 31, 2012

Stock-Based Awards and Programs

Schedule of compensation expense and tax benefits for stock-based awards and programs

	Three Months Ended				Twelve Months Ended
	2012		2011		2012		2011
Compensation expense	$	822	$	741	$	1,846	$	3,136
Tax benefit recognized	298		271		642		1,143

Schedule of assumptions used in valuation of performance-based restricted stock awards

	Fair Value of Grants Outstanding at March 31,
	2012	2011
Risk-free interest rate	0.16% to 0.45%	0.61% to 1.15%
Expected volatility of Empire stock	21.5%	26.1%
Expected volatility of peer group stock	13.5% to 51.9%	21.1% to 82.2%
Expected dividend yield on Empire stock	4.9%	6.3%
Expected forfeiture rates	3%	3%
Plan cycle	3 years	3 years
Fair value percentage	41.0% to 104.0%	97.0% to 143.0%
Weighted average fair value per share	$13.63	$27.20

Schedule of non-vested restricted stock awards (based on target number) and changes during the reporting period

	2012				2011
	Number of shares		Weighted Average Grant Date Price		Number of shares		Weighted Average Grant Date Price
Outstanding at January 1,	37,400		$	19.28	47,500		$	19.86
Granted	10,000		$	20.97	10,900		$	21.84
Awarded	(7,823	)	$	18.12	(39,621	)	$	21.92
Awarded in Excess of Target	—		—		18,621		$	21.92
Not Awarded	(5,677	)	$	18.12	—		—
Nonvested at March 31,	33,900		$	20.25	37,400		$	19.28

Schedule of assumptions used in the valuations of stock options

	Fair Value of Grants Outstanding at March 31,
	2012	2011
Risk-free interest rate	0.17% to 0.83%	0.45% to 2.39%
Dividend yield	4.9%	6.3%
Expected volatility	25.0%	23.0%
Expected life in months	78	78
Market value	$20.35	$21.79
Weighted average fair value per option	$1.56	$1.94

Schedule of stock options activity

	2012			2011
		Weighted Average			Weighted Average
	Options	Exercise Price		Options	Exercise Price
Outstanding at January 1,	190,300	$	21.56	267,400	$	21.69
Granted	—	$	—	—	$	—
Exercised	27,000	$	18.12	—	—
Outstanding at March 31,	163,300	$	22.13	267,400	$	21.69
Exercisable at March 31,	128,500	$	23.15	205,600	$	22.73

Schedule of aggregate intrinsic values of stock options

	2012	2011
Aggregate intrinsic value (in millions)	Less than $0.1	$0.2
Weighted-average remaining contractual life of outstanding options	3.9 years	5.8 years
Range of exercise prices	$18.36 to $23.81	$18.12 to $23.81
Total unrecognized compensation expense (in millions) related to non-vested options and related dividend equivalents granted under the plan	Less than $0.1	$0.1
Recognition period	Less than 1 year	1 to 2 years

Schedule of shares of time-vested restricted stock granted to qualified individuals at the fair market value

	March 31, 2012			December 31, 2011
		Weighted			Weighted
		Average Fair			Average Fair
	Number of shares	Market Value		Number of shares	Market Value
Outstanding at January 1,	3,433	$	21.84	—	$	—
Granted	—	—		10,200	$	21.84
Vested	—	—		794	$	19.32
Distributed	133	$	20.13	661	$	21.02
Forfeited	—	—		6,106	$	—
Vested but not distributed	—	—		133	$	20.13
Outstanding at end of period	3,300	$	20.35	3,433	$	21.84

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Summary of Significant Accounting Policies

3 Months Ended

Mar. 31, 2012

Summary of Significant Accounting Policies

Summary of Significant Accounting Policies

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, 2011.

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, 2011, of which there were none.

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (USD $) In Thousands, unless otherwise specified	3 Months Ended		12 Months Ended
	Mar. 31, 2012	Mar. 31, 2011	Mar. 31, 2012	Mar. 31, 2011
Net income	$ 9,804	$ 11,922	$ 52,854	$ 50,732
Reclassification adjustments for loss included in net income or reclassified to regulatory asset or liability				5,814
Net change in fair market value of open derivative contracts for period				(361)
Income taxes				(2,078)
Comprehensive income	$ 9,804	$ 11,922	$ 52,854	$ 54,107

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Segment Information

3 Months Ended

Mar. 31, 2012

Segment Information

Segment Information

Note 11— Segment Information

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

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

	For the quarter ended March 31,
	2012
	Electric		Gas		Other		Eliminations			Total
($-000’s)
Statement of Income Information
Revenues	$	119,726	$	15,683	$	1,883	$	(148	)	$	137,144
Depreciation and amortization	13,569		919		447		—			14,935
Federal and state income taxes	5,187		697		315		—			6,199
Operating income	18,243		2,054		513		—			20,810
Interest income	170		72		—		(63		)	179
Interest expense	10,027		977		—		(63		)	10,941
Income from AFUDC (debt and equity)	98		—		—		—			98
Net income	8,173		1,119		512		—			9,804
Capital Expenditures	$	34,079	$	725	$	944	$	—		$	35,748

	For the quarter ended March 31,
	2011
	Electric		Gas		Other		Eliminations			Total
($-000’s)
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 twelve months ended March 31,
	2012
	Electric		Gas		Other		Eliminations			Total
($-000’s)
Statement of Income Information
Revenues	$	515,641	$	41,124	$	7,113	$	(592	)	$	563,286
Depreciation and amortization	55,778		3,539		1,821		—			61,138
Federal and state income taxes	31,197		991		1,064		—			33,252
Operating income	88,557		5,374		1,966		—			95,897
Interest income	702		260		—		(250		)	712
Interest expense	39,086		3,910		5		(250		)	42,751
Income from AFUDC (debt and equity)	583		3		—		—			586
Net income	49,542		1,582		1,730		—			52,854
Capital Expenditures	$	110,728	$	4,507	$	4,133	$	—		$	119,368

	For the twelve months ended March 31,
	2011
	Electric		Gas		Other		Eliminations			Total
($-000’s)
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

	As of March 31, 2012
	Electric		Gas(1)		Other		Eliminations			Total
($-000’s)
Balance Sheet Information
Total assets	$	1,940,782	$	146,331	$	27,047	$	(87,701	)	$	2,026,459

(1) Includes goodwill of $39,492.

	As of December 31, 2011
	Electric		Gas(1)		Other		Eliminations			Total
($-000’s)
Balance Sheet Information
Total assets	$	1,931,320	$	145,897	$	26,038	$	(81,420	)	$	2,021,835

(1) Includes goodwill of $39,492.

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Document and Entity Information	3 Months Ended
	Mar. 31, 2012	Apr. 30, 2012
Document and Entity Information
Entity Registrant Name	EMPIRE DISTRICT ELECTRIC CO
Entity Central Index Key	0000032689
Document Type	10-Q
Document Period End Date	Mar. 31, 2012
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		42,158,156
Document Fiscal Year Focus	2012
Document Fiscal Period Focus	Q1

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Income Taxes

3 Months Ended

Mar. 31, 2012

Income Taxes

Income Taxes

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
	2012			2011			2012			2011
Consolidated provision for income taxes	$	6.2		$	7.3		$	33.3		$	27.8
Consolidated effective federal and state income tax rates	38.7		%	37.8		%	38.6		%	35.4		%

The effective tax rate for the first quarter of 2012 is higher than 2011 mainly due to tax rates associated with lower pre-tax income. The 2012 twelve months ended March 31, 2012 effective tax is higher than the 2011 comparable period primarily due to substantially lower AFUDC income.

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. We increased our current tax liability by $10.0 million during 2010 in recognition that the $26.6 million payment may be considered taxable income in 2010.  An agreement was reached with the IRS in 2011 that allowed us to defer recognition for tax purposes of approximately $26.1 million utilizing involuntary conversion rules within the Code. Accordingly, we reduced our current tax liability based on the agreement and will recognize the $26.1 million for tax purposes over more than 50 years.

We do not have any unrecognized tax benefits as of March 31, 2012. We recognized interest or penalties of $0.0 million and $0.1 million during 2011 and 2010, respectively, related to unrecognized tax benefits in other expenses and on the balance sheet. We do not expect any significant changes to our unrecognized tax benefits over the next twelve months.

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CONSOLIDATED BALANCE SHEETS (USD $) In Thousands, unless otherwise specified	Mar. 31, 2012	Dec. 31, 2011
Plant and property, at original cost:
Electric and water	$ 2,094,840	$ 2,074,748
Natural gas	67,263	66,918
Other	35,584	34,984
Construction work in progress	36,891	24,141
Total plant and property, Gross	2,234,578	2,200,791
Accumulated depreciation and amortization	649,363	637,139
Total plant and property, Net	1,585,215	1,563,652
Current assets:
Cash and cash equivalents	2,269	5,408
Restricted cash	4,357	4,357
Accounts receivable - trade, net of allowance of $1,505 and $1,138, respectively	41,677	42,296
Accrued unbilled revenues	10,978	20,326
Accounts receivable - other	19,441	16,269
Fuel, materials and supplies	62,193	62,239
Prepaid expenses and other	11,874	14,629
Regulatory assets	3,885	7,724
Total current assets	156,674	173,248
Noncurrent assets and deferred charges:
Regulatory assets	231,428	231,922
Goodwill	39,492	39,492
Unamortized debt issuance costs	9,040	9,331
Other	4,610	4,190
Total noncurrent assets and deferred charges	284,570	284,935
Total Assets	2,026,459	2,021,835
Capitalization and Liabilities
Common stock, $1 par value, 42,114,630 and 41,977,725 shares issued and outstanding, respectively	42,115	41,978
Capital in excess of par value	621,306	618,304
Retained earnings	32,997	33,707
Total common stockholders' equity	696,418	693,989
Long-term debt (net of current portion):
Obligations under capital lease	4,666	4,739
First mortgage bonds and secured debt	399,764	487,948
Unsecured debt	199,590	199,572
Total long-term debt	604,020	692,259
Total long-term debt and common stockholders' equity	1,300,438	1,386,248
Current liabilities:
Accounts payable and accrued liabilities	43,605	59,307
Current maturities of long-term debt	75,773	933
Short-term debt	22,500	12,000
Customer deposits	11,671	11,428
Interest accrued	12,022	5,958
Unrealized loss in fair value of derivative contracts	6,171	4,769
Taxes accrued	7,177	2,634
Total current liabilities	178,919	97,029
Commitments and contingencies (Note 7)
Noncurrent liabilities and deferred credits:
Regulatory liabilities	131,667	128,440
Deferred income taxes	268,577	263,933
Unamortized investment tax credits	19,165	19,226
Pension and other postretirement benefit obligations	102,071	103,371
Unrealized loss in fair value of derivative contracts	6,028	5,081
Other	19,594	18,507
Total noncurrent liabilities and deferred credits	547,102	538,558
Total Capitalization and Liabilities	$ 2,026,459	$ 2,021,835

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Financing

3 Months Ended

Mar. 31, 2012

Financing

Financing

Note 6— Financing

On April 1, 2012, we redeemed all $74.8 million aggregate principal amount of our First Mortgage Bonds, 7.00% Series due 2024, which is classified as a current liability on the March 31, 2012 balance sheet. All $5.2 million of our First Mortgage Bonds, 5.20% Pollution Control Series due 2013, and all $8.0 million of our First Mortgage Bonds, 5.30% Pollution Control Series due 2013 were also redeemed with payment made to the trustee prior to March 31, 2012.

On April 2, 2012, we entered into a Bond Purchase Agreement for a private placement of $88 million aggregate principal amount of 3.58% First Mortgage Bonds due April 2, 2027. The first settlement of $38 million occurred on April 2, 2012 and a second settlement of $50 million is anticipated to occur on or about June 1, 2012. The bonds will mature on April 2, 2027. Interest is payable semi-annually on the bonds on each April 2 and October 2, commencing October 2, 2012. The bonds may be redeemed, at our option, at any time prior to maturity, at par plus a make whole premium, together with accrued and unpaid interest, if any, to the redemption date. The bonds have not been registered under the Securities Act of 1933, as amended, and may not be offered or sold in the United States absent registration or an applicable exemption from registration requirements. We will use the proceeds from the sale of these bonds to redeem the called bonds discussed above (including to repay short term debt initially used for such purpose). The bonds have been and will be issued under the EDE mortgage. 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.

We have an unsecured revolving credit facility of $150 million in place through January 17, 2017. 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, 2012, we are in compliance with these ratios. Our total indebtedness is 50.2% of our total capitalization as of March 31, 2012 and our EBITDA is 4.8 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, 2012. However, $22.5 million was used to back up our outstanding commercial paper.

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Fair Value Measurements

3 Months Ended

Mar. 31, 2012

Fair Value Measurements

Fair Value Measurements

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, 2012 and December 31, 2011:

($ in 000’s)

	Fair Value Measurements at Reporting Date Using
Description	Assets/(Liabilities) at Fair Value			Quoted Prices in Active Markets for Identical Liabilities (Level 1)			Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
				March 31, 2012
Net derivative liabilities*	$	(12,187	)	$	(12,187	)	$	—	$	—
				December 31, 2011
Net derivative liabilities*	$	(9,848	)	$	(9,848	)	$	—	$	—

*The only recurring measurements are derivative related and assets and liabilities are netted together in the table above.

Long-Term Debt

The carrying amount of our total debt exclusive of capital leases at March 31, 2012, was $674.8 million compared to a fair market value of approximately $726.7 million. These estimates were based on a bond pricing model, utilizing inputs classified as Level 2 in the fair value hierarchy, which include 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, 2012 or that will be realizable in the future.

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Retirement Benefits (Tables)

3 Months Ended

Mar. 31, 2012

Retirement Benefits

Schedule of net periodic benefit pension cost

	Three months ended March 31,
	Pension						SERP						OPEB
	2012			2011			2012			2011			2012			2011
Service cost	$	1,628		$	1,393		$	7		$	20		$	565		$	626
Interest cost	2,551			2,591			56			41			1,032			1,130
Expected return on plan assets	(3,076		)	(2,680		)	—			—			(1,041		)	(1,050		)
Amortization of prior service cost (1)	133			133			(2		)	(2		)	(253		)	(253		)
Amortization of net actuarial loss (1)	1,950			1,353			76			33			468			500
Net periodic benefit cost	$	3,186		$	2,790		$	137		$	92		$	771		$	953

	Twelve months ended March 31,
	Pension						SERP						OPEB
	2012			2011			2012			2011			2012			2011
Service cost	$	5,830		$	5,007		$	81		$	73		$	2,205		$	2,254
Interest cost	10,366			10,156			198			155			4,286			4,396
Expected return on plan assets	(11,534		)	(10,044		)	—			—			(4,148		)	(3,927		)
Amortization of prior service cost (1)	532			531			(8		)	(8		)	(1,011		)	(1,011		)
Amortization of net actuarial loss (1)	6,091			4,315			213			98			1,729			1,655
Net periodic benefit cost	$	11,285		$	9,965		$	484		$	318		$	3,061		$	3,367

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

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Regulatory Matters (Tables)

3 Months Ended

Mar. 31, 2012

Regulatory Matters

Components of regulatory assets and liabilities

	March 31, 2012		December 31, 2011
Regulatory Assets:
Under recovered purchased gas costs — gas segment - current	$	224	$	211
Under recovered electric fuel and purchased power costs — current	3,661		7,513
Regulatory assets, current(1)	3,885		7,724
Pension and other postretirement benefits(2)	118,417		121,058
Income taxes	49,330		49,631
Deferred construction accounting costs(3)	17,087		17,095
Unamortized loss on reacquired debt	11,333		11,610
Unsettled derivative losses — electric segment	10,117		7,839
System reliability — vegetation management	7,218		6,569
Storm costs(4)	5,025		5,303
Asset retirement obligation	4,568		3,571
Customer programs	3,718		3,408
Unamortized loss on interest rate derivative	1,383		1,462
Other	696		1,420
Under recovered purchased gas costs — gas segment	627		1,281
Deferred operating and maintenance expense	1,676		1,444
Under recovered electric fuel and purchased power costs	233		231
Regulatory assets, long-term	231,428		231,922
Total Regulatory Assets	$	235,313	$	239,646

	March 31, 2012		December 31, 2011
Regulatory Liabilities:
Costs of removal	75,923		73,562
SWPA payment for Ozark Beach lost generation	24,418		25,074
Income taxes	12,270		12,337
Deferred construction accounting costs — fuel(3)	8,266		8,304
Unamortized gain on interest rate derivative	3,669		3,711
Pension and other postretirement benefits(5)	2,675		2,939
Over recovered electric fuel and purchased power costs	4,446		2,513
Other	—		—
Regulatory liabilities, long-term	131,667		128,440
Total Regulatory Liabilities	$	131,667	$	128,440

(1)  Reflects over and under recovered costs expected to be returned or recovered, as applicable, within the next 12 months in Missouri, Kansas and Oklahoma rates.

(2) Primarily reflects regulatory assets resulting from the unfunded portion of our pension and OPEB liabilities and regulatory accounting for EDG acquisition costs. Approximately $0.1 million in pension and other postretirement benefit costs have been recognized since January 1, 2012 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)  Reflects the deferral of depreciation, operations and maintenance and carrying costs relating to Iatan 1 and Iatan 2 in accordance with our 2005 regulatory plan, as well as Plum Point construction costs incurred subsequent to February 28, 2010. All of these deferrals ended when recovery in rates began and these costs are now being amortized over the life of the plants. The regulatory plan also required us to continue to defer the fuel and purchased power expense impacts of Iatan 2, which are recorded in Non-Current Regulatory Liabilities.

Balances as of March 31, 2012	Deferred Carrying Charges		Deferred O&M	Depreciation	Total
Iatan 1	$	2,715	1,358	1,645	$	5,718
Iatan 2	$	3,873	4,279	2,718	$	10,870
Plum Point	$	65	276	158	$	499
Total					$	17,087

Balances as of December 31, 2011	Deferred Carrying Charges		Deferred O&M	Depreciation	Total
Iatan 1	$	2,728	1,363	1,652	$	5,743
Iatan 2	$	3,891	4,271	2,728	$	10,890
Plum Point	$	65	239	158	$	462
Total					$	17,095

(4)  Reflects ice storm costs incurred in 2007 and costs incurred as a result of the May 2011 tornado.

(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, 2012, regulatory liabilities and corresponding expenses have been reduced by less than $0.1 million as a result of ratemaking treatment.

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Stock-Based Awards and Programs

3 Months Ended

Mar. 31, 2012

Stock-Based Awards and Programs

Stock-Based Awards and Programs

Note 9 — Stock-Based Awards and Programs

Our performance-based restricted stock awards, stock options and their related dividend equivalents and time-vested restricted stock awards are valued as liability awards, in accordance with fair value guidelines. We allow employees to elect to have taxes in excess of the minimum statutory requirements withheld from their awards and, therefore, the awards are classified as liability instruments under the ASC guidance on share based payment. 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
	2012		2011		2012		2011
Compensation expense	$	822	$	741	$	1,846	$	3,136
Tax benefit recognized	298		271		642		1,143

Activity for our various stock plans for the three months ended March 31, 2012, 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,
	2012	2011
Risk-free interest rate	0.16% to 0.45%	0.61% to 1.15%
Expected volatility of Empire stock	21.5%	26.1%
Expected volatility of peer group stock	13.5% to 51.9%	21.1% to 82.2%
Expected dividend yield on Empire stock	4.9%	6.3%
Expected forfeiture rates	3%	3%
Plan cycle	3 years	3 years
Fair value percentage	41.0% to 104.0%	97.0% to 143.0%
Weighted average fair value per share	$13.63	$27.20

Non-vested restricted stock awards (based on target number) as of March 31, 2012 and 2011 and changes during the three months ended March 31, 2012 and 2011 were as follows:

	2012				2011
	Number of shares		Weighted Average Grant Date Price		Number of shares		Weighted Average Grant Date Price
Outstanding at January 1,	37,400		$	19.28	47,500		$	19.86
Granted	10,000		$	20.97	10,900		$	21.84
Awarded	(7,823	)	$	18.12	(39,621	)	$	21.92
Awarded in Excess of Target	—		—		18,621		$	21.92
Not Awarded	(5,677	)	$	18.12	—		—
Nonvested at March 31,	33,900		$	20.25	37,400		$	19.28

At March 31, 2012, there was $0.2 million of total unrecognized compensation cost related to estimated outstanding awards. This cost will be recognized over the outstanding years remaining in the vesting period.

Stock Options

Stock option grants vest upon satisfaction of service conditions. The cost of the awards is generally recognized over the requisite (explicit) service period. The fair value of the outstanding options was estimated as of March 31, 2012 and 2011, under a Black-Scholes methodology. The assumptions used in the valuations are shown below:

	Fair Value of Grants Outstanding at March 31,
	2012	2011
Risk-free interest rate	0.17% to 0.83%	0.45% to 2.39%
Dividend yield	4.9%	6.3%
Expected volatility	25.0%	23.0%
Expected life in months	78	78
Market value	$20.35	$21.79
Weighted average fair value per option	$1.56	$1.94

	2012			2011
		Weighted Average			Weighted Average
	Options	Exercise Price		Options	Exercise Price
Outstanding at January 1,	190,300	$	21.56	267,400	$	21.69
Granted	—	$	—	—	$	—
Exercised	27,000	$	18.12	—	—
Outstanding at March 31,	163,300	$	22.13	267,400	$	21.69
Exercisable at March 31,	128,500	$	23.15	205,600	$	22.73

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, 2012 and 2011:

	2012	2011
Aggregate intrinsic value (in millions)	Less than $0.1	$0.2
Weighted-average remaining contractual life of outstanding options	3.9 years	5.8 years
Range of exercise prices	$18.36 to $23.81	$18.12 to $23.81
Total unrecognized compensation expense (in millions) related to non-vested options and related dividend equivalents granted under the plan	Less than $0.1	$0.1
Recognition period	Less than 1 year	1 to 2 years

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

Time-Vested Restricted Stock Awards

Beginning in 2011, time-vested restricted stock awards that vest after a three-year period, were granted to qualified individuals. 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, with the remainder of the award forfeited, which is distributed six months following the date of termination. 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.

No shares of time-vested restricted stock were granted in 2012 as a result of the limitation on incentive compensation in place in 2011. A summary of time vested restricted stock activity under the plan for 2011 and 2012 is presented in the table below:

	March 31, 2012			December 31, 2011
		Weighted			Weighted
		Average Fair			Average Fair
	Number of shares	Market Value		Number of shares	Market Value
Outstanding at January 1,	3,433	$	21.84	—	$	—
Granted	—	—		10,200	$	21.84
Vested	—	—		794	$	19.32
Distributed	133	$	20.13	661	$	21.02
Forfeited	—	—		6,106	$	—
Vested but not distributed	—	—		133	$	20.13
Outstanding at end of period	3,300	$	20.35	3,433	$	21.84

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

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Commitments and Contingencies

3 Months Ended

Mar. 31, 2012

Commitments and Contingencies

Commitments and Contingencies

Note 7— Commitments and Contingencies

Legal Proceedings

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 crops due to inappropriate management of the levee system around the Iatan Generating Station, of which we are a 12% owner. This matter was set for trial beginning November 7, 2011, but has now been rescheduled for May 29, 2012. Settlement negotiations are ongoing. We are unable to predict the outcome of the law suit or estimate the amount of damages, if any.

A lawsuit has been filed in Jasper County Circuit Court against us by three of our residential customers, purporting to act on behalf of all Empire customers. These customers are seeking a refund of certain amounts paid for service provided by Empire between January 1, 2007, and December 13, 2007. We will vigorously defend against the claims made against us by these three residential customers. We filed a motion asking the court to dismiss the case on the basis that the plaintiffs have not stated a valid claim. A hearing on our motion was held April 18, 2012. At all times, we charged the three plaintiffs, and all of our customers, the rates approved by and on file with the MPSC from our 2006 rate case. The orders of the MPSC in that case were appealed by the OPC, acting on behalf of the public, and certain industrial customers. The Missouri Court of Appeals affirmed all decisions entered by the MPSC in our 2006 rate case.

Coal, Natural Gas and Transportation Contracts

(in millions)	Firm physical gas and transportation contracts		Coal and coal transportation contracts
April 1, 2012 through December 31, 2012	$	25.5	$	26.7
January 1, 2013 through December 31, 2014	45.7		46.3
January 1, 2015 through December 31, 2016	24.5		31.4
January 1, 2017 and beyond	17.8		—

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

We have entered into long and short-term agreements to purchase coal and natural gas for our energy supply and natural gas operations. Under these contracts, the natural gas supplies are divided into firm physical commitments and derivatives that are used to hedge future purchases. In the event that this gas cannot be used at our plants, the gas would be liquidated at market price or put in storage. 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 entities 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 near Osceola, Arkansas. We began receiving purchased power on September 1, 2010. Commitments under this contract total approximately $32.7 million through August 30, 2015. We have the option to purchase an undivided ownership interest in the 50 megawatts covered by the purchased power agreement in 2015.

We have a 20-year purchased power agreement, which began on December 15, 2008, with Cloud County Windfarm, LLC, owned by EDP Renewables North America LLC (formerly Horizon Wind Energy), Houston, Texas to purchase the energy generated at the approximately 105-megawatt Phase 1 Meridian Way Wind Farm located in Cloud County, Kansas. We also have a 20-year contract, which began on December 15, 2005, with Elk River Windfarm, LLC, owned by IBERDROLA RENEWABLES, Inc., to purchase the energy generated at the 150-megawatt Elk River Windfarm located in Butler County, Kansas. Although these agreements are considered operating leases under 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. We do not own any portion of these windfarms. See Note 11 under “Notes to Consolidated Financial Statements” in our Annual Report on Form 10-K for the year ended December 31, 2011 for further information.

New Construction

On January 16, 2012, we signed a contract with a third party vendor to complete environmental retrofits at our Asbury plant. The retrofits will include the installation of a pulse-jet fabric filter (baghouse), circulating dry scrubber and powder activated carbon injection system. This equipment will enable us to comply with the recently finalized Mercury and Air Toxics Standard (MATS) as further described in the Environmental Matters below. In total, the costs for this project are estimated to range from $112 million to $130 million, excluding AFUDC. Initial construction costs through March 31, 2012 were $7.9 million for 2012 and $9.2 million for the project to date, excluding AFUDC.

Leases

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

We also currently have short-term operating leases for two unit trains to meet coal delivery demands, for garage and office facilities for our electric segment and for one office facility related to our gas segment. In addition, we have capital leases for certain office equipment and 108 railcars to provide coal delivery for our ownership and purchased power agreement shares of the Plum Point generating facility.

Environmental Matters

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

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, nitrogen oxides (NOx) and mercury. In the future they are also likely to include limits on 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.

Compliance Plan

In order to comply with forthcoming environmental regulations, Empire is taking actions to implement its compliance plan and strategy (Compliance Plan).  While the Cross State Air Pollution Rule (CSAPR) that was set to take effect on January 1, 2012 was stayed in late December 2011 by the District of Columbia Circuit Court of Appeals, the MATS Rules were signed by the Environmental Protection Agency (EPA) Administrator on December 16, 2011 and became effective on April 16, 2012. MATS will require compliance by April 2015 (with flexibility for extensions for reliability reasons).  Our Compliance Plan largely follows the preferred plan presented in our most recent Integrated Resource Plan. Our Compliance Plan calls for the installation of a scrubber, fabric filter, and powder activated carbon injection system at our Asbury plant by early 2015 at a cost ranging from $112 million to $130 million, excluding AFUDC. Initial construction costs through March 31, 2012 were $7.9 million for 2012 and $9.2 million project to date, excluding AFUDC. The addition of this air quality control equipment will require the retirement of Asbury Unit 2, an 18 megawatt steam turbine that is currently used for peaking purposes. The Compliance Plan also calls for the transition of our Riverton Units 7 and 8 from operation on coal to full operation on natural gas after the summer of 2013.  Riverton Units 7 and 8, along with Riverton Unit 9, a small combustion turbine that requires steam from Unit 7 for start-up, will be retired upon the conversion of Riverton Unit 12, a recently installed simple cycle combustion turbine, to a combined cycle unit. This conversion is currently scheduled to be completed in 2016.

SO2 Emissions

The CAA regulates the amount of SO2 an affected unit can emit. Currently SO2 emissions are regulated by the Title IV Acid Rain Program and the Clean Air Interstate Rule (CAIR). On January 1, 2012, CAIR was to have been replaced by the Cross-State Air Pollution Rule (CSAPR- formerly the Clean Air Transport Rule). But, on December 30, 2011 the District of Columbia Circuit Court of Appeals issued a stay of the CSAPR.  In the meantime, while the case is reviewed, both the Title IV Acid Rain Program and CAIR will remain in effect.

The Mercury Air Toxics Standards (MATS), discussed further below, was signed on December 16, 2011, and will affect SO2 emission rates at our facilities. In addition, the compliance date for the revised SO2 National Ambient Air Quality Standards (NAAQS) is August of 2017; this will also affect SO2 emissions from our facilities. The SO2 NAAQS is discussed in more detail below.

Title IV Acid Rain Program:

Under the Title IV Acid Rain Program, each existing affected unit has been allocated a specific number of emission allowances by the U.S. Environmental Protection Agency (EPA).  Each allowance entitles the holder to emit one ton of SO2. Covered utilities, such as Empire, must have emission allowances equal to the number of tons of SO2 emitted during a given year by each of their affected units. Allowances in excess of the annual emissions are banked for future use. In 2010, our SO2 emissions exceeded the annual allocations. This deficit was covered by our banked allowances. When our Title IV Acid Rain Program SO2 allowance bank is exhausted, currently estimated to be mid to late 2013, we will need to purchase additional SO2 allowances, blend more low sulfur coal at our facilities or transition our coal-fired Riverton Units 7 and 8 to natural gas or a combination of the above. Long-term compliance with this program will be met by the Compliance Plan detailed above along with possible procurement of additional SO2 allowances. We expect the cost of compliance to be fully recoverable in our rates.

CAIR:

In 2005, the EPA promulgated CAIR under the CAA. CAIR generally calls for fossil-fueled power plants greater than 25 megawatts to reduce emission levels of SO2 and/or NOx in 28 eastern states and the District of Columbia, including Missouri, where our Asbury, Energy Center, State Line and Iatan Units No. 1 and No. 2 are located. Kansas was not included in CAIR and our Riverton Plant was not affected. Arkansas, where our Plum Point Plant is located, was included for ozone season NOx but not for SO2.

In 2008, the U.S. Court of Appeals for the District of Columbia vacated CAIR and remanded it back to EPA for further consideration, but also stayed its vacatur. As a result, CAIR became effective for NOx on January 1, 2009 and for SO2 on January 1, 2010 and required covered states to develop State Implementation Plans (SIPs) to comply with specific SO2 state-wide annual budgets.

SO2 allowance allocations under the Title IV Acid Rain Program are used for compliance in the CAIR SO2 Program. Beginning in 2010, SO2 allowances were utilized at a 2:1 ratio for our Missouri units. As a result, based on current SO2 allowance usage projections, we expected to have sufficient allowances to take us into the latter part of 2012.

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

CSAPR- formerly the Clean Air Transport Rule:

On July 6, 2010, the EPA published a proposed CAIR replacement rule entitled the Clean Air Transport Rule (CATR). As proposed and supplemented, the CATR included Missouri and Kansas under both the annual and ozone season for NOx as well as the SO2 program while Arkansas remained in the ozone season NOx program only. The final CATR was released on July 7, 2011 under the name of the CSAPR, and was set to become effective January 1, 2012. However, as mentioned above, the District of Columbia Circuit Court of Appeals stayed the rule and as of January 1, 2012, the CAIR will be in effect while the court reviews the case. When it was published, the final CSAPR required a 73% reduction in SO2 from 2005 levels by 2014. The SO2 allowances allocated under the EPA’s Title IV Acid Rain Program cannot be used for compliance with CSAPR but would continue to be used for compliance with the Title IV Acid Rain Program. Therefore, new SO2 allowances would be allocated under CSAPR and retired at one allowance per ton of SO2 emissions emitted. We would receive fewer SO2 allowances than we currently emit. Long-term compliance with this Rule will be met by the Compliance Plan detailed above along with possible procurement of additional SO2 allowances. A number of states, including Kansas, various electric utilities and industrial organizations commenced litigation in the District of Columbia Court of Appeals challenging the December 2011 stay of the CSAPR. A ruling in that litigation is expected some time in mid- to late- 2012. We expect compliance costs with the resulting rules to be recoverable in our rates.

Mercury Air Toxics Standard (MATS):

The MATS standard was fully implemented and effective as of April 16, 2012, thus requiring compliance by April 16, 2015 (with flexibility for extensions for reliability reasons). The MATS regulation does not include allowance mechanisms, instead, it establishes alternative standards for certain pollutants, including SO2 (as a surrogate for hydrogen chloride (HCI)), which must be met to show compliance with hazardous air pollutant limits (see additional discussion in the MATS section below).

SO2 National Ambient Air Quality Standard (NAAQS):

In June 2010, the EPA finalized a new 1-hour SO2 NAAQS which, for areas with no SO2 monitor, originally required modeling to determine attainment and non-attainment areas within each state, but in April 2012, the EPA announced that it is reconsidering this approach. The modeling of emission sources was to have been completed by June 2013 with compliance with the SO2 NAAQS required by August 2017. Because the EPA is reconsidering the compliance determination approach, the compliance time-frame may be pushed back. Draft guidance for 1-hour SO2 NAAQS has been published by the EPA to assist states as they prepare their SIP submissions. The EPA is also planning a rulemaking to address some of the 1-hour SO2 NAAQS implementation program elements. It is likely coal-fired generating units will need scrubbers to be capable of meeting the new 1-hour SO2 NAAQS. In addition, units will be required to include SO2 emissions limits in their Title V permits or execute consent decrees to assure attainment and future compliance.

NOx Emissions

The CAA regulates the amount of NOx an affected unit can emit. As currently operated, each of our affected units is in compliance with the applicable NOx limits. Currently, revised NOx emissions are limited by the CAIR (subject to the outcome of the CSAPR proceedings) and by ozone NAAQS rules (discussed below) which were established in 1997 and in 2008.

CAIR:

In 2005, the EPA promulgated CAIR under the CAA. CAIR generally calls for fossil-fueled power plants greater than 25 megawatts to reduce emission levels of NOx in 28 states, including Missouri, where our Asbury, Energy Center, State Line and Iatan Units No. 1 and No. 2 are located and Arkansas where the Plum Point Energy Station is located. Kansas was not included in CAIR and our Riverton Plant was not affected.

The CAIR required covered states to develop SIPs to comply with specific annual NOx state-wide allowance allocation budgets. Based on existing SIPs, we had excess NOx allowances during 2010 which were banked for future use and will be sufficient for compliance at least through the end of 2012. The CAIR NOx program also was to have been replaced by the CSAPR program January 1, 2012 but because of the court stay will remain in effect while the case is reviewed.

CSAPR:

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

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

Ozone NAAQS:

Ozone, also called ground level smog, is formed by the mixing of NOx and Volatile Organic Compounds (VOCs) in the presence of sunlight. On January 6, 2010, the EPA proposed to lower the primary NAAQS for ozone designed to protect public health to a range between 60 and 70 ppb and to set a separate secondary NAAQS for ozone designed to protect sensitive vegetation and ecosystems.

On September 2, 2011, President Obama ordered the EPA to withdraw proposed air quality standards lowering the 2008 ozone standard pending the CAA 2013 scheduled reconsideration of the ozone NAAQS (the normal 5 year reconsideration period). States will move forward with area designations based on the 2008 75 ppb standard using 2008-2010 quality assured monitoring data. Our service territory will be designated as attainment, meaning it will be in compliance with the standard. In the interim, the 1997 ozone NAAQS will remain in effect.

Mercury Air Toxics Standard (MATS)

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

The EPA issued an Information Collection Request (ICR) for determining the National Emission Standards for Hazardous Air Pollutants (NESHAP), including mercury, for coal and oil-fired electric steam generating units on December 24, 2009. This ICR included our Iatan, Asbury and Riverton plants. All ICRs were submitted as required. The EPA ICR was intended for use in developing regulations under Section 112(r) of the CAA maximum achievable emission standards for the control of the emission of hazardous air pollutants (HAPs), including mercury. The EPA proposed the first ever national mercury and air toxics standards (MATS) in March 2011. It was signed by the EPA Administrator on December 16, 2011, published in the Federal Register on February 16, 2012 and fully implemented and effective as of April 16, 2012. MATS establishes numerical emission limits to reduce emissions of heavy metals, including mercury (Hg), arsenic, chromium, and nickel, and acid gases, including HCl and hydrogen fluoride (HF). For all existing and new coal-fired electric utility steam generating units (EGUs), the proposed standard will be phased in over three years, and allows states the ability to give facilities a fourth year to comply.

The MATS regulation of HAPs in combination with CSAPR is the driving regulation behind our Compliance Plan and its implementation schedule.  We expect compliance costs to be recoverable in our rates.

Greenhouse Gases

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

On September 22, 2009, the EPA issued the final Mandatory Reporting of Greenhouse Gases Rule under the CAA which requires power generating and certain other facilities that equal or exceed an emission threshold of 25,000 metric tons of CO2e to report GHGs to the EPA annually commencing in September 2011. GHG emissions for 2010 and 2011 have been reported as required to the EPA by EDE. Under a special provision for the 2011 reporting year, EDG will incur a reporting deadline extension as a facility that contains a new reporting source. On January 11, 2012 EPA released the greenhouse gas data reported from large facilities and suppliers across the U.S. economy for the year 2010.

On December 7, 2009, responding to a 2007 U.S. 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 did not itself trigger any EPA regulations, but was 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 required the EPA to propose New Source Performance Standards (NSPS) for GHGs for fossil-fuel fired steam generating units by September 30, 2011 and to issue final GHG NSPS standards by May 26, 2012.

On March 27, 2012, the EPA proposed a Carbon Pollution Standard for new power plants. This action is designed to limit the amount of carbon emitted by electric utility generating units.

The new source performance standards (NSPS) would require all new power plants to meet a CO2 emissions limit of 1,000 pounds per megawatt hour.  This is equal to a coal-fired power plant capturing 50% or more of its emissions. The rule does offer some flexibility but would still require an average of 1,000 pounds per megawatt hour over a 30-year period.  It is expected that natural gas-fired combined cycles will meet the new standard.

The proposed rule would apply only to new fossil-fuel-fired electric utility generating units. The proposal would not apply to existing units including modifications such as changes needed to meet other air pollution standards. At this time, EPA has publicly announced no plans to restrict GHG emissions from existing power plants.

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

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

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

Water Discharges

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

The Riverton Units 7 and 8 and Iatan Unit 1, which utilize once-through cooling water, were affected by regulations for Cooling Water Intake Structures issued by the EPA under the CWA Section 316(b) Phase II. The regulations became final on February 16, 2004. In accordance with these regulations, we submitted sampling and summary reports to the Kansas Department of Health and Environment (KDHE) which indicate that the effect of the cooling water intake structure on Empire Lake’s aquatic life is insignificant. KCP&L, who operates Iatan Unit 1, submitted the appropriate sampling and summary reports to the Missouri Department of Natural Resources (MDNR).

In 2007 the United States Court of Appeals for the Second Circuit remanded key sections of these CWA regulations to the EPA. As a result, the EPA suspended the regulations and revised and signed a pre-publication proposed regulation on March 28, 2011 and is obligated to finalize the rule by July 27, 2012. We will not know the full impact of these rules until they are finalized. If adopted in their present form, we expect regulations of Cooling Water Intake Structures issued by the EPA under the CWA Section 316(b) to have an impact at Riverton ranging from minor improvements to the cooling water intake structure to retirement of units 7 and 8. Impacts at Iatan 1 could range from flow velocity reductions or traveling screen modifications for fish handling to installation of a closed cycle cooling tower retrofit. Our new Iatan Unit 2 and Plum Point Unit 1 are covered by the proposed regulation but were constructed with cooling towers, the proposed Best Technology Available. We expect them to be unaffected or minimally impacted by the final rule.

Surface Impoundments

We own and maintain coal ash impoundments located at our Riverton and Asbury Power Plants. Additionally, we own a 12% interest in a coal ash impoundment at the Iatan Generating Station and a 7.52% interest in a coal ash impoundment at Plum Point. The EPA has announced its intention to revise its wastewater effluent limitation guidelines under the CWA for coal-fired power plants sometime in 2012. Once the new guidelines are issued, the EPA and states would incorporate the new standards into wastewater discharge permits, including permits for coal ash impoundments. We do not have sufficient information at this time to estimate additional costs that might result from any new standards. All of the coal ash impoundments are compliant with existing state and federal regulations.

On June 21, 2010, the EPA proposed a new regulation pursuant to the Federal Resource Conservation and Recovery Act (RCRA) governing the management and storage of Coal Combustion Residuals (CCR). In the proposal, the EPA presents two options: (1) regulation of CCR under RCRA subtitle C as a hazardous waste and (2) regulation of CCR under RCRA subtitle D as a non-hazardous waste. The public comment period closed in November 2010. It is anticipated that the final regulation will be published in mid to late 2012. We expect compliance with either option as proposed to result in the need to construct a new landfill and the conversion of existing ash handling from a wet to a dry system(s) at a potential cost of up to $15 million at our Asbury and Riverton Power Plants. This preliminary estimate will likely change based on the final CCR rule and its requirements. We expect resulting costs to be recoverable in our rates.

On September 23, 2010 and on November 4, 2010 representatives from GEI Consultants, on behalf of the EPA, conducted on-site inspections of our Riverton and Asbury coal ash impoundments, respectively. The consultants performed a visual inspection of the impoundments to assess the structural integrity of the berms surrounding the impoundments, requested documentation related to construction of the impoundments, and reviewed recently completed engineering evaluations of the impoundments and their structural integrity. In response to the inspection comments, a qualified engineering firm has been selected to complete the recommended geotechnical studies and install new flow monitoring devices and settlement monuments at both coal ash impoundments. The project is expected to be completed by December 2012. The project will comply with all corrective measures and recommendations made by the EPA in its site assessment reports.

Renewable Energy

As previously discussed, we have purchased power agreements with Cloud County Windfarm, LLC, located in Cloud County, Kansas and Elk River Windfarm, LLC, located in Butler County, Kansas. We do not own any portion of either windfarm.  More than 15% of the energy we put into the grid comes from these long-term Purchased Power Agreements (PPAs). 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.

Missouri regulations currently require 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. We have satisfied the current compliance requirements of the rule. Two percent of the renewable energy sources must be solar. We believe we are exempted from the solar requirement. A challenge to our exemption, brought by two of our customers and Power Source Solar, Inc., was dismissed on May 31, 2011 by the Missouri Western District Court of Appeals. The plaintiffs filed in the Missouri Supreme Court for transfer of the case from the Missouri Western District to the Missouri Supreme Court. The transfer was denied.

Renewable energy standard compliance rules were published by the MPSC on July 7, 2010.  Missouri investor-owned utilities and others initiated litigation to challenge these rules. On June 30, 2011, a Cole County Circuit Court judge ruled that portions of the MPSC rules were unlawful and unreasonable, in conflict with Missouri statute and in violation of the Missouri Constitution. Subsequent to that decision, a portion of the appeal was dropped and the entire order was stayed.  On December 27, 2011 the judge issued another order identical to the one that was stayed except that the rulings with regard to the constitutionality issue had been omitted. Kansas established a renewable portfolio standard (RPS), effective November 19, 2010. It requires 10% of our Kansas retail customer peak capacity requirements to be sourced from renewables by 2011, 15% by 2016, and 20% by 2020. In addition, there are several proposals currently before the U.S. Congress to adopt a nationwide RPS.

We have been selling the majority of our RECs and plan to continue to sell all or a portion of them moving forward. As a result of these REC sales, we cannot claim the underlying energy is renewable. Once a REC has been claimed or retired, it cannot be used for any other purpose. At the end of 2011, sufficient RECs, including hydro, were retired to comply with the Missouri and Kansas requirements through the end of November 2011. Additional RECs were retired in January of 2012 to complete the process for 2011. In the future, we will continue to retain a sufficient amount of RECs to meet any current or future RPS.

Gas Segment

The acquisition of Missouri Gas in June 2006 involved the property transfer of two former manufactured gas plant (FMGP) sites previously owned by Aquila, Inc. and its predecessors. 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 Site #2 in Marshall, Missouri. We have incurred $0.2 million in remediation costs and estimate further remediation costs at these two FMGP sites to be minimal.

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Retirement Benefits

3 Months Ended

Mar. 31, 2012

Retirement Benefits

Retirement Benefits

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
	2012			2011			2012			2011			2012			2011
Service cost	$	1,628		$	1,393		$	7		$	20		$	565		$	626
Interest cost	2,551			2,591			56			41			1,032			1,130
Expected return on plan assets	(3,076		)	(2,680		)	—			—			(1,041		)	(1,050		)
Amortization of prior service cost (1)	133			133			(2		)	(2		)	(253		)	(253		)
Amortization of net actuarial loss (1)	1,950			1,353			76			33			468			500
Net periodic benefit cost	$	3,186		$	2,790		$	137		$	92		$	771		$	953

	Twelve months ended March 31,
	Pension						SERP						OPEB
	2012			2011			2012			2011			2012			2011
Service cost	$	5,830		$	5,007		$	81		$	73		$	2,205		$	2,254
Interest cost	10,366			10,156			198			155			4,286			4,396
Expected return on plan assets	(11,534		)	(10,044		)	—			—			(4,148		)	(3,927		)
Amortization of prior service cost (1)	532			531			(8		)	(8		)	(1,011		)	(1,011		)
Amortization of net actuarial loss (1)	6,091			4,315			213			98			1,729			1,655
Net periodic benefit cost	$	11,285		$	9,965		$	484		$	318		$	3,061		$	3,367

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

In accordance with our regulatory agreements, our funding policy is to make contributions that are at least equal to the greater of either the minimum funding requirements of ERISA or the accrued cost of the plan. We have contributed $5.1 million to our Pension Trust in 2012 and expect our remaining 2012 contribution to be approximately $6.0 million. The actual minimum funding requirements will be determined based on the results of the actuarial valuations. Our OPEB funding policy is to contribute annually an amount at least equal to the actuarial cost of postretirement benefits.

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Regulated Operating Expense

3 Months Ended

Mar. 31, 2012

Regulated Operating Expense

Regulated Operating Expense

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
	2012		2011		2012		2011
Electric transmission and distribution expense	$	4,108	$	3,823	$	15,647	$	13,992
Natural gas transmission and distribution expense	652		562		2,476		2,225
Power operation expense (other than fuel)	3,794		2,677		14,394		11,129
Customer accounts and assistance expense	2,434		2,536		10,108		11,234
Employee pension expense (1)	2,536		1,844		9,496		6,279
Employee healthcare plan (1)	2,238		1,621		8,056		7,001
General office supplies and expense	2,752		2,898		10,011		11,807
Administrative and general expense	4,219		3,647		14,868		13,126
Allowance for uncollectible accounts	593		82		3,935		3,133
Miscellaneous expense	22		25		84		164
Total	$	23,348	$	19,715	$	89,075	$	80,090

(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, Kansas and Oklahoma jurisdictions.

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Risk Management and Derivative Financial Instruments (Details 4) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2012 counterparty
Contingent Features
Aggregate fair value of all derivative instruments with the credit-risk-related contingent features that are in a liability position	$ 3.1
Collateral which the entity would have been required to post with the counterparty if the credit-risk-related contingent features were triggered	$ 3.1
Number of Conterparties	1
Gas
Price Risk Mitigation for Gas Segment
Target percentage of storage capacity utilization	95.00%
Volume of storage in pipelines that serve customers (in Dth)	800,000
Number of pipelines that serve customers (in units)	3
Storage capacity utilized (as a percent)	37.00%
Number of future winter seasons for which minimum of expected gas usage is hedged (in seasons)	2
Gas Usage Hedged By Winter Season
Dth Hedged Financial	880,000
Dth Hedged Physical	81,770
Dth in Storage	$ 756,565
Gas | Current Winter Season
Gas Usage Hedged By Winter Season
End of Year Minimum % Hedged (as a percent)	50.00%
Dth Hedged Financial	780,000
Dth Hedged Physical	81,770
Dth in Storage	$ 756,565
Actual % Hedged (as a percent)	48.00%
Gas | Second Winter Season
Gas Usage Hedged By Winter Season
End of Year Minimum % Hedged (as a percent)	50.00%
Dth Hedged Financial	100,000
Actual % Hedged (as a percent)	2.00%
Gas | Third Winter Season
Gas Usage Hedged By Winter Season
End of Year Minimum % Hedged (as a percent)	20.00%

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Fair Value Measurements (Tables)

3 Months Ended

Mar. 31, 2012

Fair Value Measurements

Schedule of assets measured at fair value using the market value approach on a recurring basis

	Fair Value Measurements at Reporting Date Using
Description	Assets/(Liabilities) at Fair Value			Quoted Prices in Active Markets for Identical Liabilities (Level 1)			Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
				March 31, 2012
Net derivative liabilities*	$	(12,187	)	$	(12,187	)	$	—	$	—
				December 31, 2011
Net derivative liabilities*	$	(9,848	)	$	(9,848	)	$	—	$	—

*The only recurring measurements are derivative related and assets and liabilities are netted together in the table above.

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Segment Information (Tables)

3 Months Ended

Mar. 31, 2012

Segment Information

Schedule of statement of Income information, balance sheet information, and capital expenditures by business segment

	For the quarter ended March 31,
	2012
	Electric		Gas		Other		Eliminations			Total
($-000’s)
Statement of Income Information
Revenues	$	119,726	$	15,683	$	1,883	$	(148	)	$	137,144
Depreciation and amortization	13,569		919		447		—			14,935
Federal and state income taxes	5,187		697		315		—			6,199
Operating income	18,243		2,054		513		—			20,810
Interest income	170		72		—		(63		)	179
Interest expense	10,027		977		—		(63		)	10,941
Income from AFUDC (debt and equity)	98		—		—		—			98
Net income	8,173		1,119		512		—			9,804
Capital Expenditures	$	34,079	$	725	$	944	$	—		$	35,748

	For the quarter ended March 31,
	2011
	Electric		Gas		Other		Eliminations			Total
($-000’s)
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 twelve months ended March 31,
	2012
	Electric		Gas		Other		Eliminations			Total
($-000’s)
Statement of Income Information
Revenues	$	515,641	$	41,124	$	7,113	$	(592	)	$	563,286
Depreciation and amortization	55,778		3,539		1,821		—			61,138
Federal and state income taxes	31,197		991		1,064		—			33,252
Operating income	88,557		5,374		1,966		—			95,897
Interest income	702		260		—		(250		)	712
Interest expense	39,086		3,910		5		(250		)	42,751
Income from AFUDC (debt and equity)	583		3		—		—			586
Net income	49,542		1,582		1,730		—			52,854
Capital Expenditures	$	110,728	$	4,507	$	4,133	$	—		$	119,368

	For the twelve months ended March 31,
	2011
	Electric		Gas		Other		Eliminations			Total
($-000’s)
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

	As of March 31, 2012
	Electric		Gas(1)		Other		Eliminations			Total
($-000’s)
Balance Sheet Information
Total assets	$	1,940,782	$	146,331	$	27,047	$	(87,701	)	$	2,026,459

(1) Includes goodwill of $39,492.

	As of December 31, 2011
	Electric		Gas(1)		Other		Eliminations			Total
($-000’s)
Balance Sheet Information
Total assets	$	1,931,320	$	145,897	$	26,038	$	(81,420	)	$	2,021,835

(1) Includes goodwill of $39,492.

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Retirement Benefits (Details) (USD $)	3 Months Ended		12 Months Ended
	Mar. 31, 2012	Mar. 31, 2011	Mar. 31, 2012	Mar. 31, 2011
Pensions
Net Periodic Pension Benefit Cost:
Service cost	$ 1,628,000	$ 1,393,000	$ 5,830,000	$ 5,007,000
Interest cost	2,551,000	2,591,000	10,366,000	10,156,000
Expected return on plan assets	(3,076,000)	(2,680,000)	(11,534,000)	(10,044,000)
Amortization of prior service cost	133,000	133,000	532,000	531,000
Amortization of net actuarial loss	1,950,000	1,353,000	6,091,000	4,315,000
Net periodic benefit cost	3,186,000	2,790,000	11,285,000	9,965,000
Employer contribution	5,100,000
Defined Benefit Plan Estimated Employer Contributions in Current Fiscal Year	6,000,000
SERP
Net Periodic Pension Benefit Cost:
Service cost	7,000	20,000	81,000	73,000
Interest cost	56,000	41,000	198,000	155,000
Amortization of prior service cost	(2,000)	(2,000)	(8,000)	(8,000)
Amortization of net actuarial loss	76,000	33,000	213,000	98,000
Net periodic benefit cost	137,000	92,000	484,000	318,000
OPEB
Net Periodic Pension Benefit Cost:
Service cost	565,000	626,000	2,205,000	2,254,000
Interest cost	1,032,000	1,130,000	4,286,000	4,396,000
Expected return on plan assets	(1,041,000)	(1,050,000)	(4,148,000)	(3,927,000)
Amortization of prior service cost	(253,000)	(253,000)	(1,011,000)	(1,011,000)
Amortization of net actuarial loss	468,000	500,000	1,729,000	1,655,000
Net periodic benefit cost	$ 771,000	$ 953,000	$ 3,061,000	$ 3,367,000

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CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $) In Thousands, except Share data, unless otherwise specified	Mar. 31, 2012	Dec. 31, 2011
CONSOLIDATED BALANCE SHEETS
Accounts receivable - trade, allowance (in dollars)	$ 1,505	$ 1,138
Common stock, par value (in dollars per share)	$ 1	$ 1
Common stock, shares issued	42,114,630	41,977,725
Common stock, shares outstanding	42,114,630	41,977,725

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Risk Management and Derivative Financial Instruments

3 Months Ended

Mar. 31, 2012

Risk Management and Derivative Financial Instruments

Risk Management and Derivative Financial Instruments

Note 4— Risk Management and Derivative Financial Instruments

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

All derivative instruments are recognized at fair value on the balance sheet with the unrealized losses or gains from derivatives used to hedge our fuel costs in our electric segment recorded in regulatory assets or liabilities. All gains and losses from derivatives related to the gas segment are also 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, 2012 and December 31, 2011, we have recorded the following assets and liabilities representing the fair value of derivative financial instruments, (in thousands):

		March 31,		December 31,
ASSET DERIVATIVES		2012		2011
Non-designated hedging instruments due to regulatory accounting	Balance Sheet Classification	Fair Value		Fair Value
	Non-current assets and deferred charges — Other	$	12	$	2
Total derivatives assets		$	12	$	2

LIABILITY DERIVATIVES
Non-designated as hedging instruments due to regulatory accounting		March 31, 2012		December 31, 2011
Natural gas contracts, gas segment	Current liabilities	$	1,097	$	967
	Non-current liabilities and deferred credits	3		86
Natural gas contracts, electric segment	Current liabilities	5,074		3,802
	Non-current liabilities and deferred credits	6,025		4,995
Total derivatives liabilities		$	12,199	$	9,850

Electric

At March 31, 2012, approximately $5.1 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):

	Income Statement Classification of	Amount of Gain / (Loss) Reclassed from OCI into Income (Effective portion)
Derivatives in Cash Flow Hedging	Gain / (Loss) on	Three Months Ended				Twelve Months Ended
Relationships - Electric Segment	Derivative	2012		2011		2012		2011
Commodity contracts	Fuel and purchased power expense	$	—	$	—	$	—	$	(5,814	)
Total Effective - Electric Segment		$	—	$	—	$	—	$	(5,814	)

	Statement of	Amount of Gain / (Loss) Recognized in OCI on Derivative (Effective portion)
Derivatives in Cash Flow Hedging	Comprehensive	Three Months Ended				Twelve Months Ended
Relationships - Electric Segment	Income	2012		2011		2012		2011
Commodity contracts	Fuel and purchased power expense	$	—	$	—	$	—	$	(361	)
Total Effective - Electric Segment		$	—	$	—	$	—	$	(361	)

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, 2012 and 2011, respectively.

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):

Non-Designated Hedging Instruments	Balance Sheet	Amount of Gain / (Loss) Recognized on Balance Sheet
— Due to Regulatory Accounting	Classification of Gain /	Three Months Ended					Twelve Months Ended
Electric Segment	(Loss) on Derivative	2012			2011		2012			2011
Commodity contracts — electric segment	Regulatory (assets)/liabilities	$	(2,302	)	$	632	$	(9,899	)	$	(2,037	)
Total Electric Segment		$	(2,302	)	$	632	$	(9,899	)	$	(2,037	)

Non-Designated Hedging Instruments	Statement of Operations	Amount of Gain / (Loss) Recognized in Income on Derivative
— Due to Regulatory Accounting	Classification of Gain /	Three Months Ended					Twelve Months Ended
Electric Segment	(Loss) on Derivative	2012			2011		2012			2011
Commodity contracts	Fuel and purchased power expense	$	(24	)	$	160	$	(2,416	)	$	(592	)
Total Electric Segment		$	(24	)	$	160	$	(2,416	)	$	(592	)

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 March 31, 2012, the following volumes and percentage of our anticipated volume of natural gas usage for our electric operations for the remainder of 2012 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 2012	66	%	2,111,000	1,110,000	$	6.363
2013	44	%	2,020,000	1,440,000	$	6.079
2014	20	%	460,000	1,240,000	$	5.514
2015	11	%	—	1,010,000	$	5.439
2016	—		—	—	—

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, 2012, we had 0.8 million Dths in storage on the three pipelines that serve our customers. This represents 37% 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, 2012 (in thousands).

Season	Minimum % Hedged	Dth Hedged — Financial	Dth Hedged — Physical	Dth in Storage	Actual % Hedged
Current	50%	780,000	81,770	756,565	48	%
Second	Up to 50%	100,000	—	—	2	%
Third	Up to 20%	—	—	—	—
Total		880,000	81,770	756,565

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).

Non-Designated Hedging	Balance Sheet Classification of	Amount of Gain / (Loss) Recognized on Balance Sheet
Instruments Due to Regulatory	Gain or (Loss) on	Three Months Ended						Twelve Months Ended
Accounting — Gas Segment	Derivative	2012			2011			2012			2011
Commodity contracts	Regulatory assets	$	(655	)	$	(96	)	$	(2,475	)	$	(595	)
Total - Gas Segment		$	(655	)	$	(96	)	$	(2,475	)	$	(595	)

Contingent Features

Certain of our derivative instruments contain provisions that require our senior unsecured debt to maintain an investment grade credit rating with any relevant credit rating agency. If our debt were to fall below investment grade, it would be in violation of these provisions, and the counterparties to the derivative instruments could request increased collateralization on derivative instruments in net liability positions. The aggregate fair value of all derivative instruments with the credit-risk-related contingent features that are in a liability position on March 31, 2012 is $3.1 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, 2012, we would have been required to post $3.1 million of collateral with one of our counterparties. On March 31, 2012, we had no collateral posted with this counterparty.

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Income Taxes (Tables)

3 Months Ended

Mar. 31, 2012

Income Taxes

Schedule of consolidated effective federal and state income tax rates

	Three Months Ended						Twelve Months Ended
	2012			2011			2012			2011
Consolidated provision for income taxes	$	6.2		$	7.3		$	33.3		$	27.8
Consolidated effective federal and state income tax rates	38.7		%	37.8		%	38.6		%	35.4		%

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Financing (Details 2) (Unsecured revolving credit facility, USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012 quarter
Unsecured revolving credit facility
SHORT-TERM BORROWINGS
Unsecured revolving credit facility	$ 150
Maximum percentage of total indebtedness to total capitalization under the financial covenants of the credit facility agreement	62.50%
Minimum interest coverage ratio based on EBITDA under the financial covenants of the credit facility agreement	2
Number of trailing fiscal quarters used for calculating the interest coverage ratio based on EBITDA under the financial covenants of the credit facility agreement	4
Total indebtedness as a percent of total capitalization	50.20%
EBITDA coverage ratio over interest charges	4.8
Aggregate amount of default on other indebtedness subject to cross-default under the terms of the credit facility.	10
Amount of credit facility used to back up outstanding commercial paper borrowings	$ 22.5

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Risk Management and Derivative Financial Instruments (Tables)

3 Months Ended

Mar. 31, 2012

Risk Management and Derivative Financial Instruments

Schedule of fair value of derivative financial instruments, balance sheet classification

		March 31,		December 31,
ASSET DERIVATIVES		2012		2011
Non-designated hedging instruments due to regulatory accounting	Balance Sheet Classification	Fair Value		Fair Value
	Non-current assets and deferred charges — Other	$	12	$	2
Total derivatives assets		$	12	$	2

LIABILITY DERIVATIVES
Non-designated as hedging instruments due to regulatory accounting		March 31, 2012		December 31, 2011
Natural gas contracts, gas segment	Current liabilities	$	1,097	$	967
	Non-current liabilities and deferred credits	3		86
Natural gas contracts, electric segment	Current liabilities	5,074		3,802
	Non-current liabilities and deferred credits	6,025		4,995
Total derivatives liabilities		$	12,199	$	9,850

Schedule of derivatives in cash flow hedging relationships, income statement classification of gain/(loss) and comprehensive income - electric segment

	Income Statement Classification of	Amount of Gain / (Loss) Reclassed from OCI into Income (Effective portion)
Derivatives in Cash Flow Hedging	Gain / (Loss) on	Three Months Ended				Twelve Months Ended
Relationships - Electric Segment	Derivative	2012		2011		2012		2011
Commodity contracts	Fuel and purchased power expense	$	—	$	—	$	—	$	(5,814	)
Total Effective - Electric Segment		$	—	$	—	$	—	$	(5,814	)

	Statement of	Amount of Gain / (Loss) Recognized in OCI on Derivative (Effective portion)
Derivatives in Cash Flow Hedging	Comprehensive	Three Months Ended				Twelve Months Ended
Relationships - Electric Segment	Income	2012		2011		2012		2011
Commodity contracts	Fuel and purchased power expense	$	—	$	—	$	—	$	(361	)
Total Effective - Electric Segment		$	—	$	—	$	—	$	(361	)

Schedule of mark-to-market pre-tax gains/(losses) from non-designated derivative instruments - electric segment

Non-Designated Hedging Instruments	Balance Sheet	Amount of Gain / (Loss) Recognized on Balance Sheet
— Due to Regulatory Accounting	Classification of Gain /	Three Months Ended					Twelve Months Ended
Electric Segment	(Loss) on Derivative	2012			2011		2012			2011
Commodity contracts — electric segment	Regulatory (assets)/liabilities	$	(2,302	)	$	632	$	(9,899	)	$	(2,037	)
Total Electric Segment		$	(2,302	)	$	632	$	(9,899	)	$	(2,037	)

Non-Designated Hedging Instruments	Statement of Operations	Amount of Gain / (Loss) Recognized in Income on Derivative
— Due to Regulatory Accounting	Classification of Gain /	Three Months Ended					Twelve Months Ended
Electric Segment	(Loss) on Derivative	2012			2011		2012			2011
Commodity contracts	Fuel and purchased power expense	$	(24	)	$	160	$	(2,416	)	$	(592	)
Total Electric Segment		$	(24	)	$	160	$	(2,416	)	$	(592	)

Schedule of volumes and percentage of anticipated volume of natural gas usage for entity's electric operations

Dth Hedged

Year	% Hedged		Physical	Financial	Average Price
Remainder 2012	66	%	2,111,000	1,110,000	$	6.363
2013	44	%	2,020,000	1,440,000	$	6.079
2014	20	%	460,000	1,240,000	$	5.514
2015	11	%	—	1,010,000	$	5.439
2016	—		—	—	—

Schedule of minimum percentage hedged by year in the entity's procurement guidelines

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

Schedule of minimum percentage of winter season usage hedged by year of the entity's gas operations

Season	Minimum % Hedged	Dth Hedged — Financial	Dth Hedged — Physical	Dth in Storage	Actual % Hedged
Current	50%	780,000	81,770	756,565	48	%
Second	Up to 50%	100,000	—	—	2	%
Third	Up to 20%	—	—	—	—
Total		880,000	81,770	756,565

Schedule of non-designated hedging instruments due to regulatory accounting - gas segment

Non-Designated Hedging	Balance Sheet Classification of	Amount of Gain / (Loss) Recognized on Balance Sheet
Instruments Due to Regulatory	Gain or (Loss) on	Three Months Ended						Twelve Months Ended
Accounting — Gas Segment	Derivative	2012			2011			2012			2011
Commodity contracts	Regulatory assets	$	(655	)	$	(96	)	$	(2,475	)	$	(595	)
Total - Gas Segment		$	(655	)	$	(96	)	$	(2,475	)	$	(595	)