Quarterly Report (10-q)

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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, 2015

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, 2015, 43,600,726 shares of common stock were outstanding.

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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 Balance Sheets	6
	c. Consolidated Statements of Cash Flows	8
	d. Notes to Consolidated Financial Statements	9
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	26
	Executive Summary	26
	Results of Operations	28
	Rate Matters	34
	Markets and Transmission	35
	Liquidity and Capital Resources	35
	Contractual Obligations	39
	Dividends	39
	Off-Balance Sheet Arrangements	39
	Critical Accounting Policies and Estimates	39
	Recently Issued Accounting Standards	39
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	39
Item 4.	Controls and Procedures	42
Part II -	Other Information:	42
Item 1.	Legal Proceedings	42
Item 1A.	Risk Factors	42
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	42
Item 6.	Exhibits	42
	Signatures	44

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FORWARD LOOKING STATEMENTS

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

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

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

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

· the results of prudency and similar reviews by regulators of costs we incur, including capital expenditures and fuel and purchased power costs, including any regulatory disallowances that could result from prudency reviews;

· unauthorized physical or virtual access to our facilities and systems and acts of terrorism, including, but not limited to, cyber-terrorism;

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

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

· costs and activities associated with markets and transmission, including the Southwest Power Pool (SPP) regional transmission organization (RTO) transmission development, and SPP Day-Ahead Market;

· the impact of energy efficiency and alternative energy sources;

· electric utility restructuring, including deregulation;

· 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;

· volatility in the credit, equity and other financial markets and the resulting impact on 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 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;

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

· the cost and availability of purchased power and fuel, including costs and activities associated with the SPP Day-Ahead Market, and the results of our activities (such as hedging) to reduce the volatility of such costs;

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

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

· our potential inability to attract and retain an appropriately qualified workforce;

· changes in accounting requirements;

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

· performance of acquired businesses; 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 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.

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PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

	Three Months Ended
	March 31,
	2015			2014
	(000’s except per share amounts)
Operating revenues:
Electric	$	142,641		$	153,089
Gas	19,818			24,609
Other	2,085			1,975
	164,544			179,673
Operating revenue deductions:
Fuel and purchased power	48,977			55,586
Cost of natural gas sold and transported	11,423			15,045
Regulated operating expenses	28,551			27,957
Other operating expenses	805			716
Maintenance and repairs	10,267			10,257
Depreciation and amortization	20,020			17,940
Provision for income taxes	8,884			12,174
Other taxes	10,904			10,510
	139,831			150,185
Operating income	24,713			29,488

Other income and (deductions):
Allowance for equity funds used during construction	978			1,252
Interest income	11			41
Benefit for other income taxes	113			53
Other - non-operating expense, net	(698		)	(345		)
	404			1,001
Interest charges:
Long-term debt	10,751			10,105
Short-term debt	73			5
Allowance for borrowed funds used during construction	(564		)	(741		)
Other	220			215
	10,480			9,584
Net income	$	14,637		$	20,905

Weighted average number of common shares outstanding - basic	43,531			43,111

Weighted average number of common shares outstanding — diluted	43,612			43,144

Total earnings per weighted average share of common stock — basic and diluted	$	0.34		$	0.48

Dividends declared per share of common stock	$	0.26		$	0.255

See accompanying Notes to Consolidated Financial Statements.

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THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

	Twelve Months Ended
	March 31,
	2015			2014
	(000’s except per share amounts)
Operating revenues:
Electric	$	582,043		$	560,740
Gas	47,051			54,157
Other	8,107			7,966
	637,201			622,863
Operating revenue deductions:
Fuel and purchased power	208,477			185,690
Cost of natural gas sold and transported	23,403			28,914
Regulated operating expenses	111,285			106,153
Other operating expenses	3,076			3,064
Maintenance and repairs	46,784			41,973
Loss on plant disallowance	86			—
Depreciation and amortization	75,264			71,146
Provision for income taxes	36,108			42,185
Other taxes	37,493			36,445
	541,976			515,570

Operating income	95,225			107,293

Other income and (deductions):
Allowance for equity funds used during construction	6,147			4,579
Interest income	20			100
Benefit for other income taxes	237			54
Other - non-operating expense, net	(1,655		)	(1,273		)
	4,749			3,460
Interest charges:
Long-term debt	41,283			40,509
Short-term debt	181			17
Allowance for borrowed funds used during construction	(3,320		)	(2,522		)
Other	995			1,028
	39,139			39,032

Net income	$	60,835		$	71,721

Weighted average number of common shares outstanding - basic	43,395			42,916

Weighted average number of common shares outstanding — diluted	43,460			42,936

Total earnings per weighted average share of common stock — basic and diluted	$	1.40		$	1.67

Dividends declared per share of common stock	$	1.03		$	1.01

See accompanying Notes to Consolidated Financial Statements.

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THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS (UNAUDITED)

	March 31, 2015		December 31, 2014
	($-000’s)
Assets
Plant and property, at original cost:
Electric	$	2,432,098	$	2,420,824
Gas	80,112		79,364
Other	41,447		41,394
Construction work in progress	151,023		112,097
	2,704,680		2,653,679
Accumulated depreciation and amortization	758,765		743,407
	1,945,915		1,910,272

Current assets:
Cash and cash equivalents	2,661		2,105
Restricted cash	4,726		4,726
Accounts receivable — trade, net of allowance of $1,355 and $1,021 respectively	52,755		45,444
Accrued unbilled revenues	16,595		25,945
Accounts receivable — other	30,047		41,256
Fuel, materials and supplies	56,167		57,799
Prepaid expenses and other	31,789		27,879
Unrealized gain in fair value of derivative contracts	1,466		3,901
Regulatory assets	8,650		10,752
	204,856		219,807
Noncurrent assets and deferred charges:
Regulatory assets	204,947		209,717
Goodwill	39,492		39,492
Unamortized debt issuance costs	8,672		8,821
Other	3,697		2,147
	256,808		260,177
Total Assets	$	2,407,579	$	2,390,256

(Continued)

See accompanying Notes to Consolidated Financial Statements.

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THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS (UNAUDITED) (Continued)

	March 31, 2015		December 31, 2014
	($-000’s)
Capitalization and Liabilities
Common stock, $1 par value, 43,572,712 and 43,479,186 shares issued and outstanding, respectively	$	43,573	$	43,479
Capital in excess of par value	652,290		649,543
Retained earnings	93,595		90,276
Total common stockholders’ equity	789,458		783,298

Long-term debt (net of current portion):
Obligations under capital lease	3,799		3,875
First mortgage bonds and secured debt	697,624		697,615
Unsecured debt	101,703		101,699
Total long-term debt	803,126		803,189
Total long-term debt and common stockholders’ equity	1,592,584		1,586,487

Current liabilities:
Accounts payable and accrued liabilities	55,342		83,420
Current maturities of long-term debt	320		292
Short-term debt	53,000		44,000
Regulatory liabilities	5,559		7,898
Customer deposits	13,920		13,747
Interest accrued	14,671		6,565
Unrealized loss in fair value of derivative contracts	6,685		6,469
Taxes accrued	10,260		3,380
Other current liabilities	408		356
	160,165		166,127
Commitments and contingencies (Note 7)

Noncurrent liabilities and deferred credits:
Regulatory liabilities	133,303		128,471
Deferred income taxes	390,455		377,452
Unamortized investment tax credits	18,361		18,367
Pension and other postretirement benefit obligations	93,165		93,863
Unrealized loss in fair value of derivative contracts	4,488		3,243
Other	15,058		16,246
	654,830		637,642
Total Capitalization and Liabilities	$	2,407,579	$	2,390,256

See accompanying Notes to Consolidated Financial Statements.

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THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

	Three Months Ended
	March 31,
	2015			2014
	($-000’s)
Operating activities:
Net income	$	14,637		$	20,905
Adjustments to reconcile net income to cash flows from operating activities:
Depreciation and amortization including regulatory items	23,056			19,491
Pension and other postretirement benefit costs, net of contributions	1,704			3,320
Deferred income taxes and unamortized investment tax credit, net	7,203			2,145
Allowance for equity funds used during construction	(978		)	(1,252		)
Stock compensation expense	651			1,381
Non-cash (gain)/loss on derivatives	772			(683		)

Cash flows impacted by changes in:
Accounts receivable and accrued unbilled revenues	12,475			7,326
Fuel, materials and supplies	1,632			4,290
Prepaid expenses, other current assets and deferred charges	2,984			(1,326		)
Accounts payable and accrued liabilities	(28,343		)	(22,873		)
Interest, taxes accrued and customer deposits	15,159			20,781
Asset retirement obligations	—			(17		)
Other liabilities and other deferred credits	3,800			1,084

Net cash provided by operating activities	54,752			54,572

Investing activities:
Capital expenditures — regulated	(52,954		)	(45,882		)
Capital expenditures and other investments — non-regulated	(520		)	(481		)
Restricted cash	—			596

Net cash used in investing activities	(53,474		)	(45,767		)

Financing activities:
Proceeds from issuance of common stock, net of issuance costs	1,664			2,416
Net short-term borrowings	9,000			500
Dividends	(11,318		)	(10,994		)
Other	(68		)	(57		)

Net cash used in financing activities	(722		)	(8,135		)

Net increase in cash and cash equivalents	556			670

Cash and cash equivalents at beginning of period	2,105			3,475

Cash and cash equivalents at end of period	$	2,661		$	4,145

See accompanying Notes to Consolidated Financial Statements.

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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 customers in 48 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, 2014.

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, 2014.

Note 2 - Recently Issued and Proposed Accounting Standards

Revenue from contracts with customers: In June 2014, the FASB issued new guidance governing revenue recognition. Under the new guidance, an entity is required to recognize revenue in a pattern that depicts the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The new standard is effective for interim and annual reporting periods beginning after December 15, 2016; however, the FASB has proposed a one year delay in the effective date of this guidance. We are evaluating the impact of the adoption of this standard.

Extraordinary and unusual items: In January 2015, the FASB issued revised guidance that eliminates from GAAP the concept of extraordinary items. Under the revised guidance, an entity will no longer be required to separately classify, present and disclose events or transactions that are determined to be both unusual in nature and infrequent in occurrence. The revised guidance is effective for interim and annual reporting periods beginning after December 15, 2015. The application of this standard is not expected to have a material impact on our results of operations, financial position or liquidity.

Presentation of debt issuance costs: In April 2015, the FASB issued revised guidance addressing the presentation requirements for debt issuance costs. Under the revised guidance, all costs incurred to issue debt are to be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability. The revised guidance is effective for interim and annual reporting periods beginning after December 15, 2015. We are evaluating the impact of the adoption of this standard.

See Note 1 under “Notes to Consolidated Financial Statements” in our Annual Report on Form 10-K for the year ended December 31, 2014 for further information regarding recently issued and proposed accounting standards.

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Note 3— Regulatory Matters

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

Regulatory Assets and Liabilities

	March 31, 2015			December 31, 2014
Regulatory Assets:
Current:
Under recovered fuel costs	$	323		$	2,618
Current portion of long-term regulatory assets	8,327			8,134
Regulatory assets, current	8,650			10,752
Long-term:
Pension and other postretirement benefits(1)	108,341			111,121
Income taxes	47,101			47,177
Deferred construction accounting costs(2)	15,389			15,521
Unamortized loss on reacquired debt	10,236			10,405
Unsettled derivative losses — electric segment	10,155			9,037
System reliability — vegetation management	4,025			5,337
Storm costs(3)	4,009			4,183
Asset retirement obligation	5,413			5,145
Customer programs	5,280			5,253
Unamortized loss on interest rate derivative	932			943
Deferred operating and maintenance expense	661			910
Under recovered fuel costs	—			640
Current portion of long-term regulatory assets	(8,327		)	(8,134		)
Other	1,732			2,179
Regulatory assets, long-term	204,947			209,717
Total Regulatory Assets	$	213,597		$	220,469

	March 31, 2015			December 31, 2014
Regulatory Liabilities:
Current:
Over recovered fuel costs	$	2,058		$	4,227
Current portion of long-term regulatory liabilities	3,501			3,671
Regulatory liabilities, current	5,559			7,898
Long-term:
Costs of removal	92,259			90,527
SWPA payment for Ozark Beach lost generation	16,064			16,744
Income taxes	11,406			11,451
Deferred construction accounting costs — fuel(4)	7,809			7,849
Unamortized gain on interest rate derivative	3,159			3,201
Pension and other postretirement benefits	2,011			2,369
Over recovered fuel costs	4,096			1
Current portion of long-term regulatory liabilities	(3,501		)	(3,671		)
Regulatory liabilities, long-term	133,303			128,471
Total Regulatory Liabilities	$	138,862		$	136,369

(1) Primarily consists of unfunded pension and other postretirement benefits (OPEB) liability. See Note 8.

(2) Reflects deferrals resulting from 2005 regulatory plan relating to Iatan 1, Iatan 2 and Plum Point. These amounts are being recovered over the life of the plants.

(3) Reflects ice storm costs incurred in 2007 and costs incurred as a result of the May 2011 tornado including an accrued carrying charge and deferred depreciation totaling $3.2 million at March 31, 2015.

(4) Resulting from regulatory plan requiring deferral of the fuel and purchased power impacts of Iatan 2.

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Note 4— Risk Management and Derivative Financial Instruments

We engage in hedging activities in an effort to minimize our risk from the volatility of natural gas prices and power cost risk associated with exposure to congestion costs. 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 began acquiring Transmission Congestion Rights (TCR) in 2013 in an attempt to mitigate the cost of power we purchase from the Southwest Power Pool (SPP) Integrated Market (IM) due to congestion exposure. TCRs entitle the holder to a stream of revenues (or charges) based on the day-ahead congestion on the transmission path. TCRs can be purchased or self-converted using rights allocated based on prior investments made in the transmission system. 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. The unrealized losses or gains from derivatives used to hedge our fuel and purchased power costs in our electric segment are 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 Accounting Standards Codification (ASC) guidance on regulated operations, given that those gains or losses are probable of refund or recovery, respectively, through our fuel adjustment mechanisms.

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 instruments 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 mechanism.

As of March 31, 2015 and December 31, 2014, we have recorded the following assets and liabilities representing the fair value of derivative financial instruments, (in thousands):

		March 31,		December 31,
ASSET DERIVATIVES		2015		2014
Hedging instruments	Balance Sheet Classification	Fair Value		Fair Value
Natural gas contracts, gas segment	Current assets	$	—	$	—

Natural gas contracts, electric segment	Current assets			1
	Non-current assets and deferred charges — other			—
Transmission congestion rights, electric segment	Current assets	1,466		3,900
Total derivatives assets		$	1,466	$	3,901

		March 31,		December 31,
LIABILITY DERIVATIVES		2015		2014
Hedging instruments	Balance Sheet Classification	Fair Value		Fair Value
Natural gas contracts, gas segment	Current liabilities	$	171	$	476

Natural gas contracts, electric segment	Current liabilities	6,514		5,993
	Non-current liabilities and deferred credits	4,488		3,243
Total derivatives liabilities		$	11,173	$	9,712

Electric Segment

At March 31, 2015, approximately $6.5 million of unrealized net losses are applicable to natural gas financial instruments which will settle within the next twelve months.

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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	2015			2014		2015			2014

Commodity contracts	Regulatory (assets)/liabilities	$	(2,540	)	$	1,758	$	(11,077	)	$	(1,002	)

Transmission congestion rights	Regulatory (assets)/liabilities	1,105			629		13,434			2,596
Total Electric Segment		$	(1,435	)	$	2,387	$	2,357		$	1,594

Non-Designated Hedging Instruments	Statement of Income	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	2015			2014		2015			2014

Commodity contracts	Fuel and purchased power Expense	$	(1,421	)	$	754	$	(3,834	)	$	(1,856	)

Transmission congestion rights	Fuel and purchased power expense	3,438			800		13,743			881
Total Electric Segment		$	2,017		$	1,554	$	9,909		$	(975	)

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 exemption contain a price adjustment feature and will account for these contracts accordingly.

As of March 31, 2015, the following volumes and percentage of our anticipated volume of natural gas usage for our electric operations for the remainder of 2015 and for the next four years are shown below at the following average prices per Dekatherm (Dth). 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.

			Dth Hedged				Procurement
Year	% Hedged		Physical	Financial	Average Price		Guidelines
Remainder 2015	57	%	800,000	3,610,000	$	4.41	Up to 100%
2016	42	%	1,976,000	2,100,000	$	4.10	60%
2017	20	%	782,900	1,300,000	$	4.13	40%
2018	10	%	565,000	500,000	$	4.12	20%
2019	—		—	—	—		10%

At March 31, 2015, the following transmission congestion rights (TCR) have been obtained to hedge congestion risk in the SPP IM (dollars in thousands):

Year	Monthly MWH Hedged	$ Value
2015	1,421	$	1,465,637

Gas Segment

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

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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, 2015, we had 0.2 million Dths in storage on the three pipelines that serve our customers. This represents 12% 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, 2015 (in thousands).

Season	Minimum % Hedged	Dth Hedged — Financial	Dth Hedged — Physical	Dth in Storage	Actual % Hedged
Current	50%	800,000	—	235,924	32	%
Second	Up to 50%	—	—	—	—
Third	Up to 20%	—	—	—	—

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	Amount of Gain / (Loss) Recognized on Balance Sheet
Instruments Due to Regulatory	Classification of Gain or	Three Months Ended					Twelve Months Ended
Accounting — Gas Segment	(Loss) on Derivative	2015			2014		2015			2014

Commodity contracts	Regulatory (assets)/liabilities	$	(17	)	$	82	$	(478	)	$	24
Total - Gas Segment		$	(17	)	$	82	$	(478	)	$	24

Contingent Features

Certain of our derivative instruments contain provisions that are triggered if we fail to maintain an investment grade credit rating with any relevant credit rating agency. If our debt were to fall below investment grade, the counterparties to the derivative instruments could request increased collateralization on derivative instruments in net liability positions. We had no derivative instruments with the credit-risk-related contingent features in a net liability position on March 31, 2015 and have posted no collateral with counterparties in the normal course of business. Amounts reported as margin deposit assets represent our funds held on deposit for our contracts held with our NYMEX 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 the dates shown. There were no margin deposit liabilities at these dates.

	March 31, 2015		December 31, 2014
(in millions)
Margin deposit assets	$	11.1	$	9.1

Offsetting of derivative assets and liabilities

We believe that entering into master trading and netting agreements mitigates the level of financial loss that could result from a default under derivatives agreements by allowing net settlement of derivative assets and liabilities. We generally enter into the following master trading and netting agreements: (1) the International Swaps and Derivatives Association Agreement, a standardized financial natural gas and electric contract; and (2) the North American Energy Standards Board Inc. Agreement, a standardized contract for the purchase and sale of natural gas. These master trading

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and netting agreements allow the counterparties to net settle sale and purchase transactions. Collateral requirements are calculated at the master trading and netting agreement level by the counterparty.

As shown above, our asset and liability commodity contract derivatives are reported at gross on the balance sheet. ASC guidance permits companies to offset fair value amounts recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a liability) against fair value amounts recognized for derivative instruments that are executed with the same counterparty under the same master netting arrangement. For the periods ended March 31, 2015 and December 31, 2014, we did not hold any collateral posted by our counterparties. The only collateral we have posted is our margin deposit assets described above. We have elected not to offset our margin deposit assets against any of our eligible commodity contracts.

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.

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.

Our TCR positions, which are acquired on the SPP IM, are valued using the most recent monthly auction clearing prices. Our commodity contracts are valued using the market value approach on a recurring basis. The following fair value hierarchy table presents information about our TCR and commodity contracts measured at fair value as of March 31, 2015 and December 31, 2014 (in thousands):

	Fair Value Measurements at Reporting Date Using
Description	Assets/(Liabilities) at Fair Value			Quoted Prices in Active Markets for Identical Assets/(Liabilities) (Level 1)			Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	March 31, 2015
Derivative assets	$	1,466		$	—		$	1,466	$	—
Derivative liabilities	$	(11,173	)	$	(11,173	)	$	—	$	—

	December 31, 2014
Derivative assets	$	3,901		$	1		$	3,900	$	—
Derivative liabilities	$	(9,712	)	$	(9,712	)	$	—	$	—

*The only recurring measurements are derivative related.

Other fair value considerations

Our cash and cash equivalents approximate fair value because of the short-term nature of these instruments, and are classified as Level 1 in the fair value hierarchy. The carrying amount of our short-term debt, which is composed of Empire issued commercial paper or revolving credit borrowings, also approximates fair value because of their short-term nature. These instruments are classified as Level 2 in the fair value hierarchy as they are valued based on market rates for similar market transactions.

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The carrying amount of our total long-term debt exclusive of capital leases at both March 31, 2015 and at December 31, 2014 was $799 million. The fair market value at March 31, 2015 was approximately $841 million as compared to approximately $829 million at December 31, 2014. 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, 2015 or that will be realizable in the future.

Note 6— Financing

We have an unsecured revolving credit facility of $200 million in place through October 20, 2019. This agreement may be used for working capital, commercial paper back-up and general corporate purposes. The credit facility includes a $20 million swingline loan sublimit, a $20 million sublimit for letters of credit issuance and, subject to bank approval, a $75 million accordion feature and two one-year extensions of the credit facility’s maturity date.

Interest on borrowings under the facility accrues at a rate equal to, at our option, (i) the highest of (A) the agent prime rate, (B) the federal funds effective rate plus 0.5% or (C) one month LIBOR plus 1.0%, in each case, plus a margin or (ii) one month, two month, three month or six 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 is 1.025%. A facility fee is payable quarterly on the full amount of the commitments under the facility based on our current credit ratings, which is currently 0.175%.

The credit facility requires our total indebtedness to be less than 65.0% of our total capitalization at the end of each fiscal quarter and a failure to maintain this ratio will result in an event of default under the credit facility and will prohibit us from borrowing funds thereunder. As of March 31, 2015, we were in compliance with this covenant as our ratio of total indebtedness was 52% of our total capitalization. This credit facility is also subject to cross-default if we default on more than $25 million in the aggregate on our other indebtedness. As of March 31, 2015, we were not in default under any of such other indebtedness.

The credit agreement does not legally restrict the use of our cash in the normal course of operations. There were no outstanding borrowings under the agreement at March 31, 2015; however, $53.0 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. We regularly analyze this information, and provide 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.

Coal, Natural Gas and Transportation Contracts

The following table sets forth our firm physical gas, coal and transportation contracts for the periods indicated as of March 31, 2015 (in millions).

	Firm physical gas and transportation contracts		Coal and coal transportation contracts

April 1, 2015 through December 31, 2015	$	17.7	$	17.8
January 1, 2016 through December 31, 2017	42.9		26.2
January 1, 2018 through December 31, 2019	33.6		21.9
January 1, 2020 and beyond	49.6		—

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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 placed 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 as of March 31, 2015, are detailed in the table above.

Purchased Power

We currently supplement our on-system (native load) 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.

The Plum Point Energy Station (Plum Point) is a 670-megawatt, coal-fired generating facility near Osceola, Arkansas. We own, through an undivided interest, 50 megawatts of the unit’s capacity. We also have a long-term (30 year) agreement for the purchase of an additional 50 megawatts of capacity from Plum Point. Commitments under this agreement are approximately $285.0 million through August 31, 2039, the end date of the agreement. We have the option to purchase an undivided ownership interest in the 50 megawatts covered by the purchased power agreement in 2015. We evaluated this purchase option as part of our Integrated Resource Plan (IRP), which was filed with the Missouri Public Service Commission (MPSC) on July 1, 2013. It is not currently our intention to exercise this option 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, Houston, Texas to purchase the energy generated at the approximately 105-megawatt Phase 1 Meridian Way Wind Farm located in Cloud County, Kansas. Annual payments are contingent upon output of the facility and can range from zero to a maximum of approximately $14.6 million based on a 20-year average cost.

We also have a 20-year purchased power agreement, 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. Annual payments are contingent upon output of the facility and can range from zero to a maximum of approximately $16.9 million based on a 20-year average cost.

We do not own any portion of these windfarms. Payments for these agreements are recorded as purchased power expenses, and, because of the contingent nature of these payments, are not included in our operating lease obligations.

New Construction

We have in place a contract with a third party vendor to complete engineering, procurement, and construction activities at our Riverton plant to convert Riverton Unit 12 from a simple cycle combustion turbine to a combined cycle unit. The conversion includes the installation of a heat recovery steam generator (HRSG), steam turbine generator, auxiliary boiler, cooling tower, and other auxiliary equipment. The Air Emission Source Construction Permit necessary for this project was issued by the Kansas Department of Health and Environment on July 11, 2013. This conversion is currently scheduled to be completed in early to mid-2016 at a cost estimated to range from $165 million to $175 million, excluding AFUDC. This amount is included in our five-year capital expenditure

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plan. Construction costs, consisting of pre-engineering, site preparation activities and contract costs incurred project to date through March 31, 2015 were $117.7 million, excluding AFUDC.

See “Environmental Matters” below for more information.

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.

The gross amount of assets recorded under capital leases total $5.3 million at March 31, 2015.

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 these costs to be material, although recoverable in rates.

Electric Segment

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), carbon monoxide (CO), and hazardous air pollutants including mercury. In the future they will include limits on greenhouse gases (GHG) such as carbon dioxide (CO2).

Compliance Plan

In order to comply with current and forthcoming environmental regulations, we continue to implement our compliance plan and strategy (Compliance Plan). The Mercury Air Toxic Standards (MATS) and the Clean Air Interstate Rule (CAIR), replaced by the Cross State Air Pollution Rule (CSAPR), which we discuss further below, are the drivers behind our Compliance Plan and its implementation schedule. The MATS require reductions in mercury, acid gases and other emissions considered hazardous air pollutants (HAPS). They became effective in April 2012 and required full compliance by April 16, 2015 (with flexibility for extensions for reliability reasons). We are currently in material compliance with MATS. The CSAPR was first proposed by the Environmental Protection Agency (EPA) in July 2010 as a replacement of CAIR and came into effect on January 1, 2015. We anticipate compliance costs associated with the MATS, CAIR and CSAPR regulations to be recoverable in our rates.

Our Compliance Plan largely follows the preferred plan presented in our Integrated Resource Plan (IRP), filed in mid-2013 with the MPSC. In addition to the Riverton Unit 12 project discussed above, the process of installing a scrubber, fabric filter, and powder activated carbon injection system at our Asbury plant has been completed and the equipment placed in service in December 2014. This addition required the retirement of Asbury Unit 2, a steam turbine rated at 14 megawatts that was used for peaking purposes. Asbury Unit 2 was retired on December 31, 2013.

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In September 2012, we completed the transition of our Riverton Units 7 and 8 from operation on coal and natural gas to operation solely on natural gas. Riverton Unit 7 was permanently removed from service on June 30, 2014. Riverton Unit 8 and Riverton Unit 9, a small combustion turbine that requires steam from Unit 8 for start-up, are planned to be retired upon the completion of the conversion of Riverton Unit 12 to a combined cycle unit.

Air Emissions

The CAA regulates the amount of NOx and SO2 an affected unit can emit. As currently operated, each of our affected units is in compliance with the applicable NOx and SO2 limits. Beginning January 1, 2015, NOx emissions are regulated by CSAPR and National Ambient Air Quality Standards (NAAQS) rules for ozone. Beginning January 1, 2015, SO2 emissions are regulated by the Title IV Acid Rain Program and the CSAPR.

CAIR:

The CAIR generally called 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. We were in full compliance with CAIR, which ended December 31, 2014.

CSAPR:

The CSAPR requires 23 states to reduce annual SO2 and NOx emissions to help downwind areas attain NAAQS for fine particulate matter. Twenty-five states are required to reduce ozone season NOx emissions to help downwind states attain NAAQS for ozone. The CSAPR NOx annual program impacts our Missouri and Kansas units while the CSAPR NOx ozone season program impacts our units in these two states plus our unit in Arkansas.

The CSAPR divides the states required to reduce SO2 into two groups. Both groups must reduce their SO2 emissions in Phase 1. Group 1 states, which include our sources in Missouri and Arkansas, must make additional SO2 reductions for Phase 2 in order to eliminate their significant contribution to air quality problems in downwind areas. Empire’s units in Kansas are in Group 2 of the CSAPR SO2 program.

Under the CSAPR Program, in our most current five-year business plan (2015-2019), which assumes normal operations while maintaining compliance with permit conditions, we anticipate that it may be economically beneficial to purchase allowances for some of these pollutants if needed, but at the time of this writing the allowance markets have not been fully developed. We are currently in material compliance with CSAPR and expect that we will be able to meet all applicable, future CSAPR requirements.

Mercury Air Toxics Standard (MATS):

As described above, the MATS standard required compliance by April 2015. Following the completion of the Asbury air quality control system (AQCS) project and the demonstration of continuous compliance as required by the regulation, we are in material compliance with MATS.

National Ambient Air Quality Standards (NAAQS):

Under the CAA, the EPA sets NAAQS for certain emissions considered harmful to public health and the environment, including particulate matter (PM), NOx, CO, SO2, and ozone which result from fossil fuel combustion. Our facilities are currently in compliance with all applicable NAAQS.

In January 2013, the EPA finalized the revised PM 2.5 primary annual standard at 12 ug/m3 (micrograms per cubic meter of air). States are required to meet the primary standard in 2020. The standard should have no impact on our existing generating fleet because the regional ambient

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monitor results are below the PM 2.5 required level. However, the PM 2.5 standards could impact future major modifications/construction projects that require additional permits.

Ozone, also called ground level smog, is formed by the mixing of NOx and Volatile Organic Compounds (VOCs) in the presence of sunlight. Based on the current standard, our service territory is designated as attainment, meaning that it is in compliance with the standard. A revised ozone NAAQS was proposed by the EPA on November 25, 2014 and the final rule is expected in October 2015. We believe this revised Ozone NAAQS would affect our region but at this time it’s too early to determine what, if any, impact it would have on our generating plants.

Greenhouse Gases (GHGs):

EDE and EDG’s GHG emissions have been reported to the EPA as required under the Mandatory GHG Reporting Rule each year since 2010.

A series of actions and decisions including the Tailoring Rule, which regulates carbon dioxide and other GHG emissions from certain stationary sources, have further set the foundation for the regulation of GHGs. However, because of the uncertainties regarding the final outcome of the GHG regulations (discussed below), the ultimate cost of compliance cannot be determined at this time. In any case, we expect the cost of complying with any such regulations to be recoverable in our rates.

In April 2012, the EPA proposed a Carbon Pollution Standard for new power plants to limit the amount of carbon emitted by EGUs. This standard was rescinded, and a re-proposal of standards of performance for affected fossil fuel-fired EGUs was published in January 2014. The proposed rule applies only to new EGUs and sets separate standards for natural gas-fired combustion turbines and for fossil fuel-fired utility boilers. The proposal would not apply to existing units, including modifications such as those required to meet other air pollution standards which were recently completed at our Asbury facility and are currently being undertaken at the Riverton facility with the conversion of simple cycle Unit 12 to combined cycle. The final rule is expected in the summer of 2015.

On June 2, 2014, the EPA released the proposed rule for limiting carbon emissions from existing power plants. The “Clean Power Plan” requires a 30% carbon emission reduction from 2005 baseline levels by 2030 and requires fossil fuel-fired power plants across the nation, including those in Empire’s fleet, to meet state-specific goals to lower carbon levels. The EPA has identified four building block strategies to achieve the best system of emission reduction (BSER). Included in these strategies are the following: efficiency improvements at fossil fuel power plants; using lower-emitting sources (such as natural gas combined cycle units); using more renewables and keeping nuclear sources; and using power more efficiently. States will use the building blocks to craft their compliance plans or may work with other states in developing a regional approach to compliance, in which case additional time is given for implementation.

The EPA is scheduled to issue the final rule for existing power plants by summer of 2015. Each state must submit its initial compliance plan by the summer of 2016 with additional time available by request until the summer of 2017 for a single state or the summer of 2018 for a multi-state approach. The EPA received greater than 2 million public comments by the December 1, 2014 closure of the comment period. State, federal and industry representatives voiced their concerns with the regulation as written and the potential impact on electric grid reliability and the cost to implement. State and industry representatives, including Empire, continue to evaluate potential paths forward if the rule is finalized as proposed by the EPA.

Also, on June 2, 2014, the EPA released the proposed carbon pollution standards for modified and reconstructed stationary EGUs. The proposed rule focuses on electric utility steam generating units and natural gas-fired stationary combustion turbines. The comment period ended October 16, 2014 and the EPA anticipates issuing a final rule in June 2015.

Water Discharges

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

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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. In 2007, the United States Court of Appeals remanded key sections of these CWA regulations to the EPA. The EPA suspended the regulations. Following a series of court approved delays, the EPA published the final rule on August 15, 2014 with an effective date of October 14, 2014. An industry coalition has filed an appeal of the rule in the Fifth Circuit and additional court challenges are expected. We expect the regulations to have a limited impact at Riverton given the planned retirement of Unit 8 scheduled in 2016. A new intake structure design and cooling tower will be constructed as part of the Unit 12 conversion at Riverton. 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. Iatan Unit 2 and Plum Point Unit 1 are covered by the regulation, but were constructed with cooling towers, the proposed Best Technology Available. We expect them to be unaffected or minimally affected by the final rule.

Surface Impoundments

We own and maintain a coal ash impoundment located at our Asbury Power Plant. 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. As a result of the transition from coal to natural gas fuel for Riverton Units 7 and 8, the former Riverton ash impoundment has been capped and closed. Final closure as an industrial (coal combustion waste) landfill was approved on June 30, 2014 by the Kansas Department of Health and Environment (KDHE).

On April 19, 2013, the EPA signed a notice of proposed rulemaking to revise its wastewater effluent limitation guidelines and standards under the CWA for coal-fired power plants. The proposal calls for updates to operating permits beginning in July 2017. 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. Both our coal ash impoundment and closed landfill are compliant with existing state and federal regulations.

On April 17, 2015, the EPA published the final rule to regulate the disposal of coal combustion residuals (CCRs) as a non-hazardous solid waste under subtitle D of the Resource Conservation and Recovery Act (RCRA). We expect compliance to result in the need to construct a new landfill and the conversion of existing bottom ash handling from a wet to a dry system at a potential cost of up to $15 million at our Asbury Power Plant. This preliminary estimate was developed before the rule was finalized and will be updated to conform to the final rule. We expect resulting costs to be recoverable in our rates. Final closure of the existing ash impoundment is anticipated after the new landfill is operational.

We have received preliminary permit approval in Missouri for a new utility waste landfill adjacent to the Asbury plant. Our Detailed Site Investigation (DSI) has been completed and was submitted to MDNR for review and approval on January 21, 2015. Receipt of the final construction permit for the CCR waste landfill is expected in mid-summer of 2016.

Renewable Energy

On November 4, 2008 Missouri voters approved the Clean Energy Initiative (Proposition C) which currently requires Empire and other investor-owned utilities in Missouri to generate or purchase electricity from renewable energy sources, such as solar, wind, biomass and hydro power, or purchase Renewable Energy Credits (RECs), in amounts equal to at least 5% of retail sales in 2014, increasing to at least 15% by 2021. We are currently in compliance with this regulatory requirement as a result of generation from our Ozark Beach Hydroelectric Project and purchased power agreements previously mentioned with Cloud County Windfarm, LLC and Elk River Windfarm, LLC. Proposition C also requires that 2% of the energy from renewable energy sources must be solar; however, we believed that we were exempted by statute from the solar requirement. On January 20, 2013 the Earth Island Institute, d/b/a Renew Missouri, and others challenged our solar exemption by filing a complaint with the MPSC. The MPSC dismissed the complaint and Renew Missouri filed a

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notice of appeal seeking review by the Missouri Supreme Court. On February 10, 2015 the Missouri Supreme Court issued an opinion holding that the legislature had the authority to adopt the statute providing the exemption but reversed the MPSC’s holding that the two laws could be harmonized. The statute providing the exemption (which was enacted in August 2008) was impliedly repealed by the adoption of Proposition C because it conflicted with the latter law. While we are not in a position to accurately estimate the impact of this requirement, we expect any future costs to be recoverable in rates. On May 6, 2015, the MPSC ordered our request for expedited treatment of our tariff filing be granted and approved the tariff. Applicants may file for a rebate under the tariff after May 16, 2015. The law provides a number of methods that may be utilized to recover the associated expenses.

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 in 2012, increasing to 15% by 2016, and to 20% by 2020. We are currently in compliance with this regulatory requirement as a result of purchased power agreements with Cloud County Windfarm, LLC and Elk River Windfarm, LLC.

Note 8 — Retirement and Other Employee Benefits

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

	Three months ended March 31,
	Pension						SERP						OPEB
	2015			2014			2015			2014			2015			2014
Service cost	$	1,883		$	1,627		$	43		$	29		$	920		$	607
Interest cost	2,503			2,733			92			87			1,164			1,080
Expected return on plan assets	(3,390		)	(3,322		)	—			—			(1,312		)	(1,196		)
Amortization of prior service cost (1)	(157		)	105			(11		)	(2		)	(253		)	(253		)
Amortization of net actuarial loss (1)	2,345			1,649			140			105			681			228
Net periodic benefit cost	$	3,184		$	2,792		$	264		$	219		$	1,200		$	466

	Twelve months ended March 31,
	Pension						SERP						OPEB
	2015			2014			2015			2014			2015			2014
Service cost	$	6,722		$	7,213		$	167		$	148		$	2,914		$	2,792
Interest cost	10,589			10,287			393			338			4,442			3,916
Expected return on plan assets	(13,173		)	(12,625		)	—			—			(4,916		)	(4,451		)
Amortization of prior service cost (1)	156			503			(17		)	(8		)	(1,011		)	(1,011		)
Amortization of net actuarial loss (1)	7,308			9,504			539			569			1,420			1,841
Net periodic benefit cost	$	11,602		$	14,882		$	1,082		$	1,047		$	2,849		$	3,087

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

We provide certain healthcare and life insurance benefits to eligible retired employees, their dependents and survivors through trusts we have established. Participants generally become eligible for retiree healthcare benefits after reaching age 55 with 5 years of service. For employees hired after June 1, 2014, retiree healthcare benefits received upon retirement will no longer be subsidized.

In accordance with our regulatory agreements, our pension 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 expect to make pension contributions of approximately $12.8 million during 2015. 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. We expect to be required to fund approximately $5.0 million during 2015. The actual minimum funding requirements will be determined based on the results of the actuarial valuations.

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Note 9 — Equity Compensation

Our performance-based restricted stock awards 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. Grants were made in the first quarter of 2015 (the effect of which is included in the table below) but did not have a material impact on our results of operations. We had unrecognized compensation expense of $1.2 million as of March 31, 2015 which will be recognized over the remaining requisite service period.

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
	2015		2014		2015		2014
Compensation expense	$	742	$	1,349	$	3,081	$	2,636
Tax benefit recognized	271		502		1,127		955

Time-Vested Restricted Stock Awards

Our time-vested restricted stock awards vest after a three-year period. No dividend rights accumulate during the vesting period. Time-vested restricted stock is valued at an amount equal to the fair market value of our common stock on the date of grant. If employment terminates during the vesting period because of death, retirement, or disability, the participant is entitled to a pro-rata portion of the time-vested restricted stock awards such participant would otherwise have earned, which is distributed six months following the date of termination, with the remainder of the award forfeited. 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.

A summary of time vested restricted stock activity under the plan for 2014 and 2015 is presented in the table below:

	2015				2014
			Weighted				Weighted
	Number of		Average Fair		Number of		Average Fair
	shares		Market Value		shares		Market Value
Outstanding at January 1,	41,000		$	21.89	24,900		$	22.68
Granted	19,000		30.40		22,600		22.40
Vested	(1,654	)	21.92		710		24.29
Distributed					(3,300	)	22.98
Forfeited	(2,746	)	25.91		(2,490	)	—
Vested but not distributed	1,654		21.92		(710	)	—
Outstanding at end of period	57,254		$	24.81	41,710		$	21.89

Performance-Based Restricted Stock Awards

Performance-based restricted stock awards 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) are granted to qualified individuals. We estimate the fair value of outstanding restricted stock awards using a Monte Carlo option valuation model.

Non-vested performance-based restricted stock awards (based on target number) as of March 31, 2015 and 2014 and changes during the three months ended March 31, 2015 and 2014 were as follows:

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	2015				2014
	Number of shares		Weighted Average Grant Date Price		Number of shares		Weighted Average Grant Date Price
Outstanding at January 1,	63,300		$	21.74	47,200		$	21.39
Granted	21,800		$	30.40	27,000		$	22.40
Awarded	(13,653	)	$	30.55	—		—
Awarded in excess of target	3,653		$	30.55	—		—
Not awarded	0		$	0	(10,900	)	$	21.84
Granted, nonvested at March 31,	75,100		$	24.36	63,300		$	21.74

Stock Options

Beginning in 2011, we began issuing time-vested restricted stock in lieu of stock options and dividend equivalents. Prior to 2011 stock options were issued with an exercise price equal to the fair market value of the shares on the date of grant. They became exercisable after three years and expired ten years after the date granted. Dividend equivalent awards, under which dividend equivalents accumulated during the vesting period, were also issued to recipients of the stock options. Participants’ options and dividend equivalents that were not vested were forfeited when participants left Empire, except for terminations of employment under certain specified circumstances. There were no stock options or dividend equivalents granted in 2015 or 2014, and all outstanding options were exercised prior to December 31, 2014.

Stock option grants vest upon satisfaction of service conditions. The cost of the awards is generally recognized over the requisite (explicit) service period. There were no outstanding options at March 31, 2015. The fair value of the outstanding options was estimated as of March 31, 2014, under a Black-Scholes methodology.

A summary of option activity under the plan during the quarter March 31, 2014 is presented below:

	2014
		Weighted Average
	Options	Exercise Price
Outstanding at January 1,	112,500	$	23.27
Granted	—	—
Exercised	48,300	$	23.70
Outstanding at March 31,	64,200	$	23.81
Exercisable at March 31,	64,200	$	23.81

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
	2015		2014		2015		2014
Electric transmission and distribution expense	$	7,100	$	6,798	$	28,221	$	23,633
Natural gas transmission and distribution expense	677		675		2,365		2,627
Power operation expense (other than fuel)	5,317		3,991		17,415		15,989
Customer accounts and assistance expense	2,704		2,836		11,106		11,436
Employee pension expense (1)	2,684		2,626		10,648		10,720
Employee healthcare expense (1)	2,234		1,725		9,656		9,128
General office supplies and expense	2,834		4,191		13,666		13,613
Administrative and general expense	4,556		4,225		14,716		14,710
Allowance for uncollectible accounts	327		773		2,975		3,692
Miscellaneous expense	118		117		517		605
Total	$	28,551	$	27,957	$	111,285	$	106,153

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(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

The tables below present statement of income information, balance sheet information and capital expenditures of our business segments (in thousands):

	For the quarter ended March 31,
	2015
	Electric		Gas		Other		Eliminations			Total
Statement of Income Information
Revenues	$	142,641	$	19,818	$	2,430	$	(345	)	$	164,544
Depreciation and amortization	18,589		972		459		—			20,020
Federal and state income taxes	7,202		1,126		443		—			8,771
Operating income	21,214		2,788		711		—			24,713
Interest income	2		12		9		(12		)	11
Interest expense	10,091		965		—		(12		)	11,044
Income from AFUDC (debt and equity)	1,541		1		—		—			1,542
Net income	12,096		1,822		719		—			14,637

Capital Expenditures	$	52,263	$	683	$	609	$	—		$	53,555

	For the quarter ended March 31,
	2014
	Electric		Gas		Other		Eliminations			Total
Statement of Income Information
Revenues	$	153,089	$	24,609	$	2,295	$	(320	)	$	179,673
Depreciation and amortization	16,575		910		455		—			17,940
Federal and state income taxes	10,247		1,448		426		—			12,121
Operating income	25,526		3,274		688		—			29,488
Interest income	31		12		4		(6		)	41
Interest expense	9,367		964		—		(6		)	10,325
Income from AFUDC (debt and equity)	1,967		26		—		—			1,993
Net income	17,884		2,330		691		—			20,905

Capital Expenditures	$	46,703	$	3,172	$	457	$	—		$	50,332

	For the twelve months ended March 31,
	2015
	Electric		Gas		Other		Eliminations			Total
Statement of Income Information
Revenues	$	582,043	$	47,051	$	9,437	$	(1,330	)	$	637,201
Depreciation and amortization	69,547		3,822		1,895		—			75,264
Federal and state income taxes	32,692		1,519		1,660		—			35,871
Operating income	86,176		6,289		2,760		—			95,225
Interest income	7		25		27		(39		)	20
Interest expense	38,635		3,863		—		(39		)	42,459
Income from AFUDC (debt and equity)	9,408		59		—		—			9,467
Net income	55,679		2,457		2,699		—			60,835

Capital Expenditures	$	218,696	$	5,348	$	2,303	$	—		$	226,347

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	For the twelve months ended March 31,
	2014
	Electric		Gas		Other		Eliminations			Total
Statement of Income Information
Revenues	$	560,740	$	54,157	$	9,410	$	(1,444	)	$	622,863
Depreciation and amortization	65,552		3,695		1,899		—			71,146
Federal and state income taxes	38,731		1,726		1,674		—			42,131
Operating income	97,995		6,573		2,725		—			107,293
Interest income	73		56		7		(36		)	100
Interest expense	37,714		3,876		—		(36		)	41,554
Income from AFUDC (debt and equity)	7,045		56		—		—			7,101
Net Income	66,263		2,737		2,721		—			71,721

Capital Expenditures	$	163,930	$	6,859	$	2,405	$	—		$	173,194

	As of March 31, 2015
($-000’s)	Electric		Gas(1)		Other		Eliminations			Total
Balance Sheet Information
Total assets	$	2,291,695	$	131,432	$	34,961	$	(50,509	)	$	2,407,579

(1) Includes goodwill of $39,492.

	As of December 31, 2014
($-000’s)	Electric		Gas(1)		Other		Eliminations			Total
Balance Sheet Information
Total assets	$	2,271,539	$	130,856	$	34,655	$	(46,794	)	$	2,390,256

(1) Includes goodwill of $39,492.

Note 12— Income Taxes

The following table shows 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
	2015			2014			2015			2014
Consolidated provision for income taxes	$	8.8		$	12.1		$	35.9		$	42.1
Consolidated effective federal and state income tax rates	37.5		%	36.7		%	37.1		%	37.0		%

The effective income tax rate for the three and twelve month periods ended March 31, 2015 is higher than comparable periods in 2014 primarily due to lower equity AFUDC income in 2015 compared to 2014.

We do not have any unrecognized tax benefits as of March 31, 2015. We did not recognize any significant interest or penalties in any of the periods presented. We do not expect any significant changes to our unrecognized tax benefits over the next twelve months.

The Tax Increase Prevention Act (the “Act”) was signed into law on December 19, 2014. The Act restored several expired business tax provisions, including bonus depreciation for 2014. We generated $22.0 million of tax net operating losses (NOLs) during 2014, mainly due to bonus depreciation. These losses may be carried back two years and are also available to offset future taxable income until 2034. Our 2015 tax liability is expected to be higher than 2014 due to the

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expiration of bonus depreciation. However, we expect to utilize investment tax credits and NOLs to partially offset the 2015 payments.

In 2010, we received $17.7 million of investment tax credits based on our investment in Iatan 2. We utilized $0.7 million and $9.0 million of these credits on our 2012 and 2013 tax returns, respectively. Due to the passage of the Act, we were unable to use these credits on our 2014 tax return. We expect to use between $5.0 million and $7.0 million of the remaining credits on our 2015 tax return. The tax credits will have no significant income statement impact because they will flow to our customers as we amortize the tax credits over the life of the plant.

On September 13, 2013, the IRS and the Treasury Department released final regulations under Sections 162(a) and 263(a) on the deduction and capitalization of expenditures related to tangible property. These regulations apply to tax years beginning on or after January 1, 2014, and we plan to utilize the book capitalization method as allowable under the final regulations on our 2014 tax return when filed. We expect an immaterial impact to the effective tax rate based on the book capitalization method.

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, including the sale of wholesale energy to four towns in Missouri and Kansas. 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 customers in 48 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, 2015, our gross operating revenues were derived as follows:

Electric segment sales*	91.3	%
Gas segment sales	7.4
Other segment sales	1.3

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

Earnings

The following table represents our basic and diluted earnings per weighted average share of common stock for the applicable periods ended March 31 (in dollars):

	Three Months Ended				Twelve Months Ended
	2015		2014		2015		2014

Basic and diluted earnings per weighted average share of common stock	$	0.34	$	0.48	$	1.40	$	1.67

Electric and gas earnings were negatively impacted by milder weather in the first quarter of 2015 as compared to the same period in 2014 when temperatures were considerably colder than normal. A $1.4 million January 2015 refund to FERC wholesale customers, reflecting lower fuel costs from the SPP integrated market, negatively impacted results for both periods. Increased regulatory operating expenses, depreciation and amortization expenses, property and other tax expenses, and interest charges also negatively impacted results compared to the previous periods. Rate changes, primarily the June 2014 rate increase for our wholesale on-system electric customers, positively impacted results in each period presented. Increased AFUDC due to higher levels of construction activity positively impacted results during the twelve-month ended period.

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The table below sets forth a reconciliation of basic and diluted earnings per share between the three months and twelve months ended March 31, 2014 and March 31, 2015, 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. The dilutive effect of additional shares issued included in the table reflects the estimated impact of all shares issued during the periods ended March 31.

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.

In addition, although a non-GAAP presentation, we believe the presentation of gross margin (in the table below and elsewhere in this report) 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. We define electric gross margin as electric revenues less fuel and purchased power costs. We define gas gross margin as gas operating revenues less cost of gas in rates. This reconciliation and margin information may not be comparable to other companies’ presentations 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 EPS determined in accordance with GAAP as a measure of operating performance or any other measure of financial performance presented in accordance with GAAP. Management compensates for the limitations of using non-GAAP financial measures by using them to supplement GAAP results to provide a more complete understanding of the factors and trends affecting the business than GAAP results alone.

	Three Months Ended			Twelve Months Ended
Earnings Per Share — 2014	$	0.48		$	1.67

Gross Margins
Electric segment	$	(0.05	)	$	(0.02	)
Gas segment	(0.02		)	(0.02		)
Other segment	0.00			0.00
Total Gross Margin	(0.07		)	(0.04		)

Operating — electric segment	(0.01		)	(0.09		)
Operating —gas segment	0.00			0.01
Maintenance and repairs	0.00			(0.07		)
Depreciation and amortization	(0.03		)	(0.06		)
Other taxes	(0.01		)	(0.02		)
AFUDC	(0.01		)	0.04
Interest charges	(0.01		)	(0.01		)
Other income and deductions	0.00			(0.01		)
Dilutive effect of additional shares issued	0.00			(0.02		)
Earnings Per Share — 2014	$	0.34		$	1.40

Recent Activities

Regulatory Matters

Our rate cases, as we reported in our Annual Report on Form 10-K for the year ended December 31, 2014, remain unchanged except for two Non-Unanimous Stipulation and Agreements that were filed in regard to our $24.3 million rate request we filed with the Missouri Public Service Commission (MPSC) on August 29, 2014. The first Stipulation and Agreement reflects a base rate increase of $17.1 million, which includes a net reduction in base fuel and purchased power, as well as

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other issues. There were no objections to this agreement and as a result, it can be treated as a unanimous agreement by the MPSC. This stipulation remains pending before the MPSC. The second Non-Unanimous Stipulation and Agreement was filed by the parties on certain issues, primarily rate design, and an Evidentiary Hearing was held on it in April, 2015. It also remains pending before the MPSC.

A Kansas Corporation Commission (KCC) Order was received on April 15, 2015 approving the Asbury Environmental Cost Recovery (AECR) tariff rider we proposed in an application filed on December 5, 2014. Also, on February 19, 2015, the KCC approved a request we filed on January 22, 2015 for an Ad Valorem Tax Surcharge (AVTS) with the new rate effective on and after February 23, 2015. We filed a request with the Arkansas Public Service Commission (APSC) on February 23, 2015 to implement an Environmental Cost Recovery Rider (Environmental Rider) for costs associated with new environmental facilities installed at the Asbury Power Plant. The Environmental Rider took effect immediately and is subject to refund if costs are found not to be prudent by the APSC.

See “Rate Matters” below for more information.

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, 2015, compared to the same periods ended March 31, 2014.

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
	2015		2014		2015		2014
Electric	$	12.1	$	17.9	$	55.7	$	66.3
Gas	1.8		2.3		2.4		2.7
Other	0.7		0.7		2.7		2.7
Net income	$	14.6	$	20.9	$	60.8	$	71.7

Electric Segment

Electric operating revenues comprised approximately 86.7% of our total operating revenues during the first quarter of 2015.

Sales, Revenues and Gross Margin

KWh Sales

The amounts and percentage changes from the prior periods in kilowatt-hour (kWh) sales by major customer class for on-system (native load) 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	2015	2014	Change(1)		2015	2014	Change(1)
Residential	589.9	641.6	(8.1	)%	1,898.7	2,007.1	(5.4	)%
Commercial	377.2	388.5	(2.9	)	1,572.5	1,570.6	0.1
Industrial	245.7	237.1	3.6		1,040.2	1,012.0	2.8
Wholesale on-system	81.7	84.1	(2.9	)	333.9	342.7	(2.6	)
Other(2)	34.3	35.2	(2.3	)	127.2	131.6	(3.3	)
Total on-system sales	1,328.8	1,386.5	(4.2	)	4,972.5	5,064.0	(1.8	)

(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 4.2% during the first quarter of 2015 as compared to the first quarter of 2014, primarily due to decreased demand resulting from milder

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weather in the first quarter of 2015 as compared to the same period in 2014. Total heating degree days for the first quarter of 2015 were 8.4% less than the same period last year when temperatures were considerably colder than normal, but 5.1% more than the 30-year average. KWh sales for our residential and commercial customers decreased during the first quarter of 2015 as compared to the first quarter of 2014 primarily due to the decreased demand resulting from milder weather during the first quarter of 2015. Industrial kWh sales increased 3.6% mainly due to increased usage.

KWh sales for our on-system customers decreased 1.8% during the twelve months ended March 31, 2015, as compared to the same period in 2014, primarily due to decreased demand resulting from milder weather in the first quarter of 2015 and the fourth quarter of 2014 as compared to the prior year periods. Residential kWh sales, which are more weather sensitive, decreased 5.4% primarily due to the decreased demand resulting from milder weather during the first quarter of 2015. Commercial kWh sales increased slightly, due to higher sales that were partially offset by milder weather. Industrial KWh sales increased 2.8% mainly due to increased usage.

Revenues and Gross Margin

As shown in the Electric Segment Operating Revenues and Gross Margin table below, electric segment gross margin, defined as electric revenues less fuel and purchased power costs, decreased approximately $3.8 million and $1.4 million during the quarter and twelve month period ended March 31, 2015, respectively, as compared to the comparable periods in 2014 mainly due to decreased demand due to milder temperatures during the first quarter of 2015 when compared to the first quarter of 2014.

The amounts and percentage changes from the prior period’s electric segment operating revenues by major customer class for on-system and off-system sales, and the associated fuel and purchased power expense (including a reconciliation of our actual fuel and purchased power expenditures to the fuel and purchased power expense shown on our statements of income) for the applicable periods ended March 31, were as follows (dollars in millions):

Electric Segment Operating Revenues and Gross Margin

	3 months			3 months					12 months			12 months
	ended			ended					ended			ended
Customer Class	2015			2014			% Change(1)		2015			2014			% Change(1)
Residential	$	68.0		$	72.2		(5.8	)%	$	232.3		$	238.6		(2.7	)%
Commercial	39.3			40.1			(1.9	)	171.5			167.7			2.3
Industrial	19.0			18.0			5.6		85.8			81.4			5.4
Wholesale on-system	3.5			5.1			(31.5	)	20.7			20.4			1.5
Other(2)	3.9			3.9			(1.1	)	15.2			15.4			(0.8	)
Total on-system revenues	133.7			139.3			(4.0	)	525.5			523.5			0.4
Off-system wholesale(3)	0.0			3.1			(100.0	)	0.1			14.9			(99.2	)
SPP IM net revenues(3)	4.7			6.2			(24.6	)	40.3			6.2			546.3
Total revenues from KWh sales	138.4			148.6			(6.9	)	565.9			544.6			3.9
Miscellaneous revenues(4)	3.7			4.0			(6.0	)	14.1			14.0			0.4
Total electric operating revenues	$	142.1		$	152.6		(6.8	)	$	580.0		$	558.6		3.8
Water revenues	0.5			0.5			(2.9	)	2.1			2.1			(4.0	)
Total electric segment operating revenues	$	142.6		$	153.1		(6.8	)	$	582.1		$	560.7		3.8
Actual fuel and purchased power expenditures	$	37.9		$	55.0		(31.0	)	$	148.2		$	189.2		(21.7	)
SPP IM net purchases(3)	6.3			6.3			(0.5	)	55.9			6.3			780.5
Net fuel recovery and deferral	5.2			(4.8		)	208.2		6.2			(6.9		)	189.9
SWPA amortization(5)	(0.7		)	(0.8		)	13.8		(2.5		)	(2.8		)	10.9
Unrealized (gain)/loss on derivatives	0.2			(0.1		)	389.4		0.7			(0.1		)	569.9
Total fuel and purchased power expense per income statement	48.9			55.6			(11.9	)	208.5			185.7			12.3
Total Gross Margin	$	93.7		$	97.5		(3.9	)	$	373.6		$	375.0		(0.4	)

(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) The SPP IM was implemented on March 1, 2014. As of December 31, 2014, off-system revenues were effectively replaced by SPP IM activity. See “— Markets and Transmission” below for more information.

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

(5) Missouri ten year amortization of the $26.6 million payment received from the SWPA in September, 2010, of which $12.3 million of the Missouri portion remains to be amortized as of March 31, 2015.

Revenues for our on-system customers decreased $5.6 million during the first quarter of 2015 driving a $3.8 million decrease in gross margin. The change was driven primarily due to decreased sales resulting from milder weather in the first quarter of 2015 as compared to the same period in 2014. The impact of weather and other volumetric related factors decreased revenues an estimated $6.2 million. Also decreasing revenues was a $1.4 million January 2015 refund to FERC wholesale customers, reflecting lower fuel costs from the SPP integrated market. Improved customer counts increased revenues an estimated $0.5 million. Rate changes increased revenues an estimated $0.5 million. An increase in fuel recovery revenue (offset by a corresponding change in fuel expenses, resulting in no net effect on gross margin) from electric customers during the first quarter of 2015 compared to the prior year quarter increased revenues by $1.0 million.

Revenues for our on-system customers increased $2.0 million for the twelve months ended March 31, 2015, however, gross margin decreased $1.4 million. The primary driver of the margin decrease was lower sales. Rate changes contributed an estimated $5.1 million to revenues. Improved customer counts increased revenues an estimated $1.6 million. Weather and other volumetric related factors decreased revenues an estimated $10.4 million. Also decreasing revenues was a $1.4 million January 2015 refund to FERC wholesale customers, reflecting lower fuel costs from the SPP integrated market. A $7.1 million increase in fuel recovery revenue (offset by a corresponding change in fuel expenses, resulting in no net effect on gross margin) from electric customers during the twelve months ended March 31, 2015 compared to the same period in 2014 increased revenues.

SPP Integrated Marketplace (IM) and Off-System Electric Transactions

In the past, in addition to sales to our own customers, we also sold power to other utilities as available, including (since 2007) through the SPP Energy Imbalance Services (EIS) market. However, on March 1, 2014, the SPP RTO implemented a Day-Ahead Market, or Integrated Marketplace (IM), which replaces the real-time EIS market. SPP IM activity is settled for each market participant in various time increments. When we sell more generation to the market than we purchase, based on the prescribed time increments, the net sale and corresponding net revenue is included as part of electric revenues. When we purchase more generation from the market than we sell, based on the prescribed time increments, the net purchase cost is recorded as a component of fuel and purchased power on the financial statements. See the Electric Segment Operating Revenues and Gross Margin table above and “— Markets and Transmission” below. The majority of our market activity sales margin is included as a component of the fuel adjustment clause in our Missouri, Kansas and Oklahoma jurisdictions and our transmission rider in our Arkansas jurisdiction. As a result, nearly all of the market activity sales margin flows back to the customer and has little effect on margin or net income.

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Operating Expenses — Other Than Fuel and Purchased Power

The table below shows regulated operating expense increases/(decreases) during the first quarter of 2015 and the twelve months ended March 31, 2015 as compared to the same periods in 2014.

	Three Months Ended			Twelve Months Ended
(in millions)	2015 vs. 2014			2015 vs. 2014
Transmission expense(1)	$	0.4		$	4.1
Distribution expense	(0.1		)	0.5
Steam power other operating expense	1.0			0.7
Employee health care expense	0.5			0.5
Other power supply expense	0.3			0.4
Customer assistance expense	0.1			0.6
General labor expense	(1.2		)	0.5
Hydro power operating expense	0.0			0.4
Injuries and damages expense	0.1			0.1
Employee pension expense	0.1			0.0
Regulatory commission expense	0.0			(0.2		)
Professional services	0.0			(0.3		)
Customer accounts expense	(0.4		)	(0.8		)
General supplies expense	(0.3		)	(0.3		)
Property insurance	(0.2		)	(0.2		)
Other employee benefits	0.2			0.3
Director, stockholder, other expense	0.2			0.2
Water operations expense	0.0			(0.1		)
Other miscellaneous accounts (netted)	0.2			(0.2		)
TOTAL	$	0.9		$	6.2

(1) Mainly due to increased SPP transmission charges.

The table below shows maintenance and repairs expense increases/(decreases) during the first quarter of 2015 and the twelve months ended March 31, 2015 compared to the same periods in 2014.

	Three Months Ended			Twelve Months Ended
(in millions)	2015 vs. 2014			2015 vs. 2014
Transmission and distribution maintenance expense	$	(0.2	)	$	1.3
Maintenance and repairs expense at the Energy Center	0.2			1.5
Maintenance and repairs expense at the Asbury plant	0.2			1.9
Maintenance and repairs expense to SLCC	0.0			(0.2		)
Maintenance and repairs expense at the State Line plant	0.0			(0.3		)
Maintenance and repairs expense at the Iatan plant	0.1			0.2
Maintenance and repairs expense at the Plum Point plant	(0.9		)	(1.1		)
Maintenance and repairs expense at the Riverton plant — steam	0.0			0.2
Maintenance and repairs expense at the Riverton plant — gas	0.6			1.2
Other miscellaneous accounts (netted)	0.0			0.1
TOTAL	$	0.0		$	4.8

Depreciation and amortization expense increased approximately $2.0 million (12.1%) and $4.0 million (6.1%) during the quarter and twelve month periods ended March 31, 2015, respectively, primarily due to increased plant in service, reflecting completion of the Asbury AQCS project and other additions to plant in service.

Other taxes increased approximately $0.5 million and $1.1 million during the quarter and twelve month periods ended March 31, 2015, respectively, due to increased property tax (reflecting our additions to plant in service).

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Gas Segment

Gas Operating Revenues and Sales

The following table details our natural gas sales for the periods ended March 31:

	Total Gas Delivered to Customers
	Three Months Ended				Twelve Months Ended
(bcf sales)	2015	2014	% change		2015	2014	% change
Residential	1.27	1.54	(17.3	)%	2.49	2.95	(15.5	)%
Commercial(1)	0.54	0.67	(19.3	)	1.15	1.41	(18.8	)
Industrial	0.02	0.04	(45.6	)	0.05	0.07	(38.8	)
Other(2)	0.02	0.02	(19.1	)	0.03	0.04	(15.7	)
Total retail sales	1.85	2.27	(18.4	)	3.72	4.47	(17.0	)
Transportation sales(1)	1.46	1.56	(6.4	)	4.82	4.68	3.0
Total gas operating sales	3.31	3.83	(13.5	)	8.54	9.15	(6.7	)

(1)Several commercial customers transferred to transportation customers during 2014, reflecting the decrease in commercial sales and the increase in transportation sales.

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

The following table details our natural gas revenues for the periods ended March 31:

	Operating Revenues and Cost of Gas Sold
	Three Months Ended						Twelve Months Ended
($ in millions)	2015		2014		% change		2015		2014		% change
Residential	$	13.0	$	16.1	(19.0	)%	$	29.8	$	34.3	(13.2	)%
Commercial(1)	5.2		6.6		(21.8	)	12.2		14.7		(16.9	)
Industrial	0.2		0.3		(47.7	)	0.4		0.6		(31.4	)
Other(2)	0.1		0.2		(21.3	)	0.3		0.4		(15.9	)
Total retail revenues	$	18.5	$	23.2	(20.2	)	$	42.7	$	50.0	(14.5	)
Other revenues	0.1		0.1		(5.5	)	0.4		0.4		(0.0	)
Transportation revenues(1)	1.2		1.3		(7.9	)	3.9		3.7		4.1
Total gas operating revenues	$	19.8	$	24.6	(19.5	)	$	47.0	$	54.1	(13.1	)
Cost of gas sold	11.4		15.0		(24.1	)	23.4		28.9		(19.1	)
Gas segment gross margins	$	8.4	$	9.6	(12.2	)	$	23.6	$	25.2	(6.3	)

(1)Several commercial customers transferred to transportation customers during 2014, reflecting the decrease in commercial revenues and the increase in transportation revenues.

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

Gas retail sales and revenues decreased reflecting decreased demand due to milder temperatures during the first quarter of 2015 as compared to 2014 when temperatures were colder than normal. Heating degree days were 13.5% lower in the first quarter of 2015 as compared to the first quarter of 2014 but 2.4% higher than the 30-year average. As a result, our gas gross margin (defined as gas operating revenues less cost of gas in rates) decreased $1.2 million in the first quarter of 2015 as compared to the same period in 2014.

Gas retail sales and revenues decreased during the twelve months ended March 31, 2015 as compared to the same period in 2014, reflecting milder temperatures during the first quarter of 2015 as compared to 2014. Total heating degree days for the 2014-2015 gas heating season (which runs from November to March) were 10.2% lower than the 2013-2014 gas heating season but 3.3% higher than the 30-year average gas heating season. Our margin for the twelve months ended March 31, 2015 decreased $1.6 million as compared to the same period in 2014.

We have a PGA clause in place that 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, 2015, we had unrecovered purchased gas costs of $0.5 million recorded as a current regulatory liability and $1.7 million recorded as a non-current regulatory liability.

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Operating Revenue Deductions

The table below shows regulated operating expense increases/(decreases) for the applicable periods ended March 31, 2015 as compared to the same periods in 2014.

	Three Months Ended			Twelve Months Ended
(in millions)	2015 vs. 2014			2015 vs. 2014
Customer accounts expense	$	(0.2	)	$	(0.8	)
General labor expense	(0.1		)	(0.1		)
Transmission and distribution operation expense	0.0			(0.3		)
TOTAL	$	(0.3	)	$	(1.2	)

Consolidated Company

Income Taxes

The following table shows our consolidated 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
	2015			2014			2015			2014
Consolidated provision for income taxes	$	8.8		$	12.1		$	35.9		$	42.1

Consolidated effective federal and state income tax rates	37.5		%	36.7		%	37.1		%	37.0		%

See Note 12 of “Notes to Consolidated Financial Statements (Unaudited)” 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 increased during the twelve months ended March 31, 2015 as compared to the same period in 2014, reflecting the environmental retrofit project at our Asbury plant and the Riverton 12 combined cycle project. AFUDC decreased during the three months ended March 31, 2015 as compared to the same period in 2014 reflecting the completion of the environmental retrofit project at our Asbury plant in December 2014.

	Three Months Ended				Twelve Months Ended
($ in millions)	2015		2014		2015		2014
Allowance for equity funds used during construction	$	1.0	$	1.3	$	6.2	$	4.6
Allowance for borrowed funds used during construction	0.5		0.7		3.3		2.5
Total AFUDC	$	1.5	$	2.0	$	9.5	$	7.1

Total interest charges on long-term and short-term debt for the periods ended March 31 are shown below. The change in long-term debt interest for 2015 compared to 2014 reflects the issuance on December 1, 2014, of $60.0 million of 4.27% First Mortgage Bonds due December 1, 2044. The proceeds from the sale of the bonds were used to refinance existing short-term indebtedness and for general corporate purposes.

	Interest Charges
	($ in millions)
	3 Months		3 Months				12 Months		12 Months
	Ended		Ended		%		Ended		Ended		%
	2015		2014		Change		2015		2014		Change
Long-term debt interest	$	10.7	$	10.1	6.4	%	$	41.3	$	40.5	1.9	%
Short-term debt interest	0.1		0.0		>100.0		0.2		0.0		>100.0
Other interest	0.2		0.2		2.8		1.0		1.1		(3.1	)
Total interest charges	$	11.0	$	10.3	7.0		$	42.5	$	41.6	2.2

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RATE MATTERS

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

Our rates for retail electric and natural gas services (other than specially negotiated retail rates for industrial or large commercial customers, which are subject to regulatory review and approval) are determined on a “cost of service” basis. Rates are designed to provide, after recovery of allowable operating expenses, an opportunity for us to earn a reasonable return on “rate base.” “Rate base” is generally determined by reference to the original cost (net of accumulated depreciation and amortization) of utility plant in service, subject to various adjustments for deferred taxes and other items. Over time, rate base is increased by additions to utility plant in service and reduced by depreciation, amortization and retirement of utility plant or write-off’s as ordered by the utility commissions. In general, a request of new rates is made on the basis of a “rate base” as of a date prior to the date of the request and allowable operating expenses for a 12-month test period ended prior to the date of the request. Although the current rate making process provides recovery of some future changes in rate base and operating costs, it does not reflect all changes in costs for the period in which new retail rates will be in place. This results in a lag (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, 2012:

Jurisdiction	Date Requested	Annual Increase Granted		Percent Increase Granted		Date Effective
Arkansas - Electric	February 23, 2015	$	457,000	3.35	%	February 23, 2015
Kansas - Electric	January 22, 2015	$	273,455	1.08	%	February 23, 2015
Arkansas - Electric	December 3, 2013	$	1,366,809	11.34	%	September 26, 2014
Missouri — Electric	July 6, 2012	$	27,500,000	6.78	%	April 1, 2013
Missouri — Water	May 21, 2012	$	450,000	25.5	%	November 23, 2012
Kansas — Electric	June 17, 2011	$	1,250,000	5.20	%	January 1, 2012
Oklahoma — Electric	June 30, 2011	$	240,722	1.66	%	January 4, 2012

On August 29, 2014, we filed a rate request with the MPSC to increase annual revenue by $24.3 million, or approximately 5.5%, to recover operating expenses and infrastructure investments, primarily for the environmental retrofit at the Asbury power plant. There have been two Stipulation and Agreements filed on certain issues in this case. The first Stipulation and Agreement reflects a base rate increase of $17.1 million, which includes a net reduction in base fuel and purchased power, as well as other issues. There were no objections to this agreement and as a result, it can be treated as a unanimous agreement by the MPSC. A decision on the stipulation remains pending before the MPSC. A second Non-Unanimous Stipulation and Agreement was filed on certain issues, primarily rate design. An Evidentiary Hearing was held on the second stipulation in April, 2015. A decision on this stipulation also remains pending before the MPSC. The statutorily required date for revised rates is scheduled for July 26, 2015.

On December 5, 2014, we filed an Application with the KCC requesting approval of our proposed Asbury Environmental Cost Recovery (AECR) tariff rider. The request sought approval for recovery of our jurisdictional portion of annual carrying costs (rate of return, income taxes, and depreciation) of approximately $0.86 million, associated with investment in the AQCS. A Commission Order was received April 15, 2015 approving the rider in the amount of $0.78 million effective June 1, 2015.

On January 22, 2015, we filed an Application with the KCC requesting approval of our Ad Valorem Tax Surcharge (AVTS). The request sought approval for an annual increase of $0.27 million related to increases in Ad Valorem taxes which exceed amounts currently included in base rates. On February 19, 2015, the KCC approved the request. The new rate was effective on and after February 23, 2015.

On February 23, 2015, we filed a notice with the APSC to implement a tariff rider pursuant to the provision of Act 310 of 1981. The rider recovers reasonably incurred costs and expenditures as a

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direct result of legislative or regulatory requirements relating to the protection of the public health, safety, or the environment. Our implemented tariff rider recovers our Arkansas jurisdictional share of investment associated with the AQCS. The new tariff is effective upon notice (February 23, 2015) subject to refund.

Our other rate cases, as we reported in our Annual Report on Form 10-K for the year ended December 31, 2014, remain unchanged. See Note 3, “Regulatory Matters” in our Annual Report on Form 10-K for the year ended December 31, 2014 for additional information

MARKETS AND TRANSMISSION

Electric Segment

Day Ahead Market: On March 1, 2014, the SPP RTO implemented its Integrated Marketplace (IM) (or Day-Ahead Market), which replaced the Energy Imbalance Services (EIS) market. The SPP RTO created a single NERC-approved balancing authority (BA) that took over balancing authority responsibilities for its members, including Empire.

As part of the IM, we and other SPP members submit generation offers to sell our power and bids to purchase power into the SPP market, with the SPP serving as a centralized commitment and dispatch of SPP members’ generation resources. The SPP matches offers and bids based upon operating and reliability considerations. The SPP reports that approximately 90%-95% of all next day generation needed throughout the SPP territory is being cleared through the IM. We also acquire Transmission Congestion Rights (TCR) through annual and monthly processes in an attempt to mitigate congestion costs associated with the power we purchase from the IM. When we sell more generation to the market than we purchase for a given settlement period, the net sale is included as part of electric revenues. When we purchase more generation from the market than we sell, the net purchase is recorded as a component of fuel and purchased power on our financial statements. The net financial effect of these IM transactions is included in our fuel adjustment mechanisms and therefore has little impact on gross margin.

SPP/Midcontinent Independent System Operator (MISO) Joint Operating Agreement and Plum Point Delivery: Due to Plum Point’s physical location and interconnection, transmission service from Entergy/MISO is required for delivery. On December 19, 2013, Entergy voluntarily integrated its generation, transmission, and load into the MISO regional transmission organization. Based on the current terms and conditions of MISO membership, Entergy’s participation in MISO will not be beneficial to our customers as it will increase transmission delivery costs for our Plum Point power station as well as utilize our transmission system without compensation.

As a result, we have participated with the SPP members and other impacted utilities in two separate FERC settlement proceedings to address these important issues in an effort to reduce the costs to our customers. The FERC has set settlement evidentiary hearings for these issues. Both disputes are likely to move into litigation hearings before the FERC if the settlement process is unsuccessful.

Information concerning recent and pending SPP RTO and other FERC activities can be found under Note 3, “Regulatory Matters — Markets and Transmission” in our Annual Report on Form 10-K for the year ended December 31, 2014.

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 unsecured revolving credit facility) and borrowings from our unsecured revolving credit facility. Historically, we have also successfully raised funds, as needed, 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 believe the cash provided by operating activities, together

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with the amounts available to us under our credit facilities and the issuance of debt and equity securities, 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. See “Capital Requirements and Investing Activities” below for further information.

We will continue to evaluate our need to increase available liquidity based on our view of working capital requirements, including the timing of our construction programs and other factors. See Item 1A, “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2014 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)	2015			2014			Change
Cash provided by/(used in):
Operating activities	$	54.8		$	54.6		$	0.2
Investing activities	(53.5		)	(45.8		)	(7.7		)
Financing activities	(0.7		)	(8.1		)	7.4
Net change in cash and cash equivalents	$	0.6		$	0.7		$	(0.1	)

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 increase or decrease in natural gas prices directly impacts the cost of gas stored in inventory.

First Quarter 2015 Compared to 2014. During the first quarter of 2015, our net cash flows provided from operating activities increased $0.2 million, or 0.3%, from the first quarter of 2014. This change resulted from the following:

· Increased plant depreciation, mostly related to increased electric assets - $2.1 million.

· Changes in regulatory amortizations - $1.2 million.

· Net changes in fuel deferrals — $3.0 million.

· Tax timing differences, mostly related to expected utilization of 2014 tax net operating losses during 2015 - $5.1 million.

· Working capital changes for accounts receivable, accounts payable and other current assets and liabilities - $1.3 million.

· Increase in losses related to hedging positions - $1.5 million.

· Income tax receivables — $(6.3) million.

· Changes in pension and OPEB related amortizations — $(1.6) million.

· Decrease in net income - $(6.3) million.

Capital Requirements and Investing Activities

Our net cash flows used in investing activities increased $7.7 million during the first quarter of 2015 as compared to the first quarter of 2014.

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Our capital expenditures incurred totaled approximately $53.6 million during the first quarter of 2015 compared to $50.4 million in the first quarter of 2014.

A breakdown of the capital expenditures for the quarters ended March 31, 2015 and 2014 is as follows:

	Capital Expenditures
(in millions)	2015			2014
Distribution and transmission system additions	$	15.8		$	17.3
New Generation — Riverton 12 combined cycle	30.6			16.5
Additions and replacements — electric plant	3.8			10.9
Gas segment additions and replacements	0.6			3.1
Storms	0.0			0.4
Transportation	0.2			0.3
Other (including retirements and salvage - net) (1)	2.0			1.5
Subtotal	53.0			50.0
Non-regulated capital expenditures (primarily fiber optics)	0.6			0.4
Subtotal capital expenditures incurred (2)	53.6			50.4
Adjusted for capital expenditures payable (3)	(0.1		)	(4.0		)
Total cash outlay	$	53.5		$	46.4

(1) Other includes equity AFUDC of $(1.0) for 2015 and $(1.3) for 2014.

(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 81.2% of our cash requirements for capital expenditures during the first quarter of 2015 were satisfied from internally generated funds (funds provided by operating activities less dividends paid). The remaining amounts of such requirements were satisfied from short-term borrowings and proceeds from our sales of common stock and debt securities discussed below.

We estimate that internally generated funds will provide approximately 79.6% of the funds required for the remainder of our budgeted 2015 capital expenditures. We intend to utilize short-term debt to finance any additional amounts needed beyond those provided by operating activities for such capital expenditures. If additional financing is needed, we intend to utilize a combination of debt and equity securities.

Financing Activities

First quarter 2015 compared to 2014.

Our net cash flows used in financing activities was $0.8 million in the first quarter of 2015, a decrease of $7.4 million as compared to the first quarter of 2014, primarily due to the following:

· Net short-term borrowings of $9.0 million during the first quarter of 2015 as compared to $0.5 million during the first quarter of 2014.

· Proceeds from issuance of common stock of $1.7 million during the first quarter of 2015 as compared to $2.4 million during the first quarter of 2014.

· Dividends paid of $11.3 million during the first quarter of 2015 as compared to $11.0 million during the first quarter of 2014.

Shelf Registration

We have a $200.0 million shelf registration statement with the SEC, effective December 13, 2013, covering our common stock, unsecured debt securities, preference stock, and first mortgage bonds. As of March 31, 2015, $200.0 million remains available for issuance under this shelf registration statement. However, as a result of our regulatory approvals, of the original $200.0 million, $150.0 million was available for first mortgage bonds with $90.0 million remaining available after the issuance of $60 million in first mortgage bonds on December 1, 2014. We plan to use proceeds from

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offerings made pursuant to this shelf to fund capital expenditures, refinance existing debt or general corporate needs during the three-year effective period.

Credit Agreements

On October 20, 2014, we entered into a new $200 million 5-year Credit Agreement replacing the former $150 million Third Amended and Restated Unsecured Credit Agreement dated January 17, 2012. This new agreement may be used for working capital, commercial paper back-up and general corporate purposes. The credit facility includes a $20 million swingline loan sublimit, a $20 million sublimit for letters of credit issuance and, subject to bank approval, a $75 million accordion feature and two one-year extensions of the credit facility’s maturity date. There were no outstanding borrowings under this agreement at March 31, 2015. However $53.0 million was used as of March 31, 2015 to back up our outstanding commercial paper. See Note 6 of “Notes to Consolidated Financial Statements (Unaudited).”

EDE Mortgage Indenture

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 principal amount of all series of first mortgage bonds outstanding at any one time under the Indenture of Mortgage and Deed of Trust of The Empire District Electric Company (EDE Mortgage) is limited by terms of the mortgage to $1.0 billion. Based on the $1.0 billion limit, and our current level of outstanding first mortgage bonds, we are limited to the issuance of $357.0 million of new first mortgage bonds. 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, 2015 would permit us to issue approximately $541.5 million of new first mortgage bonds based on this test with an assumed interest rate of 5.5%. 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, 2015, we had retired bonds and net property additions which would enable the issuance of at least $982.6 million principal amount of bonds if the annual interest requirements are met. As of March 31, 2015, we are in compliance with all restrictive covenants of the EDE Mortgage.

EDG Mortgage Indenture

The principal amount of all series of first mortgage bonds outstanding at any one time under the Indenture of Mortgage and Deed of Trust of The Empire District Gas Company (EDG Mortgage) is limited by terms of the mortgage to $300.0 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 1.0. As of March 31, 2015, this test would allow us to issue approximately $20.0 million principal amount of new first mortgage bonds at an assumed interest rate of 5.5%.

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Credit Ratings

Corporate credit ratings and the ratings for our securities are as follows:

	Fitch	Moody’s	Standard & Poor’s
Corporate Credit Rating	n/r*	Baa1	BBB
EDE First Mortgage Bonds	BBB+	A2	A-
Senior Notes	BBB	Baa1	BBB
Commercial Paper	F3	P-2	A-2
Outlook	Stable	Stable	Stable

*Not rated

On March 6, 2015 and March 19, 2015, Moody’s and Standard & Poor’s, respectively, reaffirmed our credit ratings while Fitch reaffirmed our ratings on September 30, 2014.

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

CONTRACTUAL OBLIGATIONS

Our contractual obligations have not materially changed at March 31, 2015, compared to December 31, 2014. See “Contractual Obligations” in our Annual Report on Form 10-K for the year ended December 31, 2014.

DIVIDENDS

Holders of our common stock are entitled to dividends if 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). A reduction of our dividend per share, partially or in whole, could have an adverse effect on our common stock price.

On April 30, 2015, the Board of Directors declared a quarterly dividend of $0.26 per share on common stock payable on June 15, 2015 to holders of record as of June 1, 2015.

OFF-BALANCE SHEET ARRANGEMENTS

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

CRITICAL ACCOUNTING POLICIES

See “Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report on Form 10-K for the year ended December 31, 2014 for a discussion of additional critical accounting policies. There were no changes in these policies in the quarter ended March 31, 2015

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

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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 can be 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. We also acquire Transmission Congestion Rights (TCR) in an attempt to lessen the cost of power we purchase from the SPP IM due to congestion costs. See Note 4, of “Notes to Consolidated Financial Statements (Unaudited)”.

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 63.7% of our 2014 generation fuel supply need through coal. Approximately 96% of our 2014 coal supply was Western coal. We have contracts and binding proposals to supply a portion of the fuel for our coal plants through 2017. These contracts satisfy approximately 92% of our anticipated fuel requirements for 2015, 35% for 2016 and 18% for 2017 for our Asbury coal plant. In order to manage our exposure to fuel prices, future coal supplies will be acquired using a combination of short-term and long-term contracts.

We are exposed to changes in market prices for natural gas we must purchase to run our combustion turbine generators. Our natural gas procurement program is designed to manage our costs to avoid volatile natural gas prices. We enter into physical forward and financial derivative contracts with counterparties relating to our future natural gas requirements that lock in prices (with respect to predetermined percentages of our expected future natural gas needs) in an attempt to lessen the volatility in our fuel expenditures and improve predictability. As of March 31, 2015, 57%, or 4.4 million Dths, of our anticipated volume of natural gas usage for our electric operations for the remainder of 2015 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, 2015, our natural gas expenditures would increase by approximately $0.7 million based on our March 31, 2015 total hedged positions for the next twelve months. However, such an increase would be 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, 2015, we have 0.2 million Dths in storage on the three pipelines that serve our customers. This represents 12% of our storage capacity. We have an additional 0.8 million Dths hedged through financial derivatives and physical contracts.

See Note 4 of “Notes to Consolidated Financial Statements (Unaudited)” for further information.

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

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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 contracts held with our NYMEX 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, 2015 and December 31, 2014 (in millions).

	March 31, 2015		December 31, 2014
Margin deposit assets	$	11.1	$	9.1

There were no margin deposit liabilities at these dates.

Our exposure to credit risk is concentrated primarily within our fuel procurement process, as we transact with a smaller, less diverse group of counterparties and transactions may involve large notional volumes and potentially volatile commodity prices. Below is a table showing our net credit exposure at March 31, 2015, reflecting that our counterparties are exposed to Empire for the net unrealized mark-to-market losses for physical forward and financial natural gas contracts carried at fair value (in millions).

Net unrealized mark-to-market losses for physical forward natural gas contracts	$	4.2
Net unrealized mark-to-market losses for financial natural gas contracts	10.9
Net credit exposure	$	15.1

The $10.9 million net unrealized mark-to-market loss for financial natural gas contracts is comprised entirely of $10.9 million that our counterparties are exposed to Empire for unrealized losses. We are holding no collateral from any counterparty since we are below the $10.0 million mark-to-market collateral threshold in our agreements. As noted above, as of March 31, 2015, we have $11.1 million on deposit for NYMEX contract exposure to Empire, of which $11.1 million represents our collateral requirement. If NYMEX gas prices decreased 25% from their March 31, 2015 levels, our collateral requirement would increase $5.4 million. If these prices increased 25%, our collateral requirement would decrease $5.4 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 2015 than in 2014, our interest expense would increase, and income before taxes would decrease by less than $0.8 million. This amount has been determined by considering the impact of the hypothetical interest rates on our highest month-end commercial paper balance for 2014. 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.

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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, 2015.

There have been no changes in our internal control over financial reporting that occurred during the first quarter of 2015 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

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, 2014.

Item 5. Other Information.

For the twelve months ended March 31, 2015, our ratio of earnings to fixed charges was 2.84x. See Exhibit (12) hereto.

Item 6. Exhibits.

(a) Exhibits.

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

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

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

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

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

(101) The following financial information from The Empire District Electric Company’s Quarterly Report on Form 10-Q for the period ended March 31, 2015, filed with the SEC on May 8, 2015, formatted in Extensible Business Reporting Language (XBRL): (i) the Consolidated Statements of Income for the three and twelve month periods ended March 31, 2015 and 2014, (ii) the Consolidated Balance Sheets at March 31, 2015 and December 31, 2014, (iii) the Consolidated Statements of Cash Flows for the three-month periods ended March 31, 2015 and 2014, and (iv) Notes to Consolidated Financial Statements.**

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*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.

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SIGNATURES

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

	THE EMPIRE DISTRICT ELECTRIC COMPANY
	Registrant


	By	/s/ 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 8, 2015

EXHIBIT (12)

COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES

	Twelve
	Months Ended
	March 31, 2015

Income before provision for income taxes and fixed charges (Note A)	$	149,396,654

Fixed charges:
Interest on long-term debt	$	41,282,877
Interest on short-term debt	181,167
Other interest	995,603
Rental expense representative of an interest factor (Note B)	10,231,778

Total fixed charges	$	52,691,425

Ratio of earnings to fixed charges	2.84x

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).

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 8, 2015


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

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;

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 8, 2015


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

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, 2015 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 8, 2015

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.

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, 2015 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 8, 2015

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