EMPIRE DISTRICT ELECTRIC CO - FORM 10-Q

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EX-32.(A) - EX-32.(A) - EMPIRE DISTRICT ELECTRIC CO	a14-14062_1ex32da.htm
EX-12 - EX-12 - EMPIRE DISTRICT ELECTRIC CO	a14-14062_1ex12.htm
EX-31.(A) - EX-31.(A) - EMPIRE DISTRICT ELECTRIC CO	a14-14062_1ex31da.htm
EX-32.(B) - EX-32.(B) - EMPIRE DISTRICT ELECTRIC CO	a14-14062_1ex32db.htm
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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 June 30, 2014

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 July 31, 2014, 43,354,196 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	7
	c. Consolidated Statements of Cash Flows	9
	d. Notes to Consolidated Financial Statements	10
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	28
	Executive Summary	28
	Results of Operations	31
	Rate Matters	38
	Markets and Transmission	39
	Liquidity and Capital Resources	39
	Contractual Obligations	43
	Dividends	43
	Off-Balance Sheet Arrangements	44
	Critical Accounting Policies and Estimates	44
	Recently Issued Accounting Standards	44
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	44
Item 4.	Controls and Procedures	46
Part II-	Other Information:
Item 1.	Legal Proceedings	46
Item 1A.	Risk Factors	46
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	46
Item 6.	Exhibits	47
	Signatures	48

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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;

· 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;

· 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 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
	June 30,
	2014			2013
	(000’s except per share amounts)
Operating revenues:
Electric	$	140,767		$	127,026
Gas	6,989			7,777
Other	2,026			1,843
	149,782			136,646
Operating revenue deductions:
Fuel and purchased power	54,358			42,013
Cost of natural gas sold and transported	2,678			3,113
Regulated operating expenses	27,609			26,647
Other operating expenses	782			872
Maintenance and repairs	11,393			9,933
Depreciation and amortization	18,157			17,635
Provision for income taxes	6,694			7,042
Other taxes	8,609			8,281
	130,280			115,536
Operating income	19,502			21,110
Other income and (deductions):
Allowance for equity funds used during construction	1,522			867
Interest income	3			10
Benefit/(provision) for other income taxes	45			(7		)
Other - non-operating expense, net	(300		)	(290		)
	1,270			580
Interest charges:
Long-term debt	10,105			10,190
Short-term debt	13			12
Allowance for borrowed funds used during construction	(830		)	(472		)
Other	290			302
	9,578			10,032

Net income	$	11,194		$	11,658
Weighted average number of common shares outstanding - basic	43,236			42,707
Weighted average number of common shares outstanding - diluted	43,269			42,727
Total earnings per weighted average share of common stock — basic and diluted	$	0.26		$	0.27
Dividends declared per share of common stock	$	0.255		$	0.25

See accompanying Notes to Consolidated Financial Statements.

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THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

	Six Months Ended
	June 30,
	2014			2013
	(000’s except per share amounts)
Operating revenues:
Electric	$	293,856		$	255,788
Gas	31,598			28,270
Other	4,001			3,728
	329,455			287,786
Operating revenue deductions:
Fuel and purchased power	109,944			87,316
Cost of natural gas sold and transported	17,723			15,038
Regulated operating expenses	55,566			53,784
Other operating expenses	1,498			1,665
Maintenance and repairs	21,650			19,090
Loss on plant disallowance	—			2,409
Depreciation and amortization	36,097			33,736
Provision for income taxes	18,868			14,496
Other taxes	19,119			17,284
	280,465			244,818
Operating income	48,990			42,968
Other income and (deductions):
Allowance for equity funds used during construction	2,773			1,393
Interest income	44			517
Benefit/(provision) for other income taxes	99			(35		)
Other - non-operating expense, net	(645		)	(579		)
	2,271			1,296
Interest charges:
Long-term debt	20,210			20,141
Short-term debt	18			59
Allowance for borrowed funds used during construction	(1,570		)	(777		)
Other	504			554
	19,162			19,977
Net income	$	32,099		$	24,287
Weighted average number of common shares outstanding - basic	43,173			42,636
Weighted average number of common shares outstanding — diluted	43,200			42,652
Total earnings per weighted average share of common stock — basic and diluted	$	0.74		$	0.57
Dividends declared per share of common stock	$	0.51		$	0.50

See accompanying Notes to Consolidated Financial Statements.

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THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

	Twelve Months Ended
	June 30,
	2014			2013
	(000’s except per share amounts)
Operating revenues:
Electric	$	574,481		$	522,624
Gas	53,369			46,632
Other	8,148			6,851
	635,998			576,107
Operating revenue deductions:
Fuel and purchased power	198,034			175,456
Cost of natural gas sold and transported	28,479			23,321
Regulated operating expenses	107,115			101,963
Other operating expenses	2,974			3,026
Maintenance and repairs	43,433			39,613
Loss on plant disallowance	—			2,409
Depreciation and amortization	71,668			64,180
Provision for income taxes	41,837			35,835
Other taxes	36,773			32,689
	530,313			478,492
Operating income	105,685			97,615
Other income and (deductions):
Allowance for equity funds used during construction	5,234			2,437
Interest income	92			1,187
Benefit for other income taxes	106			105
Other - non-operating expense, net	(1,283		)	(2,060		)
	4,149			1,669
Interest charges:
Long-term debt	40,424			40,042
Short-term debt	18			87
Allowance for borrowed funds used during construction	(2,880		)	(1,392		)
Other	1,015			1,091
	38,577			39,828
Net income	$	71,257		$	59,456
Weighted average number of common shares outstanding — basic	43,048			42,512
Weighted average number of common shares outstanding — diluted	43,069			42,526
Total earnings per weighted average share of common stock — basic	$	1.66		$	1.40
Total earnings per weighted average share of common stock — diluted	$	1.65		$	1.40
Dividends declared per share of common stock	$	1.015		$	1.00

See accompanying Notes to Consolidated Financial Statements.

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THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS (UNAUDITED)

	June 30, 2014		December 31, 2013
	($-000’s)
Assets
Plant and property, at original cost:
Electric	$	2,253,657	$	2,219,605
Natural gas	77,894		72,834
Other	41,051		39,902
Construction work in progress	184,580		152,330
	2,557,182		2,484,671
Accumulated depreciation and amortization	740,989		732,737
	1,816,193		1,751,934

Current assets:
Cash and cash equivalents	2,939		3,475
Restricted cash	7,726		2,872
Accounts receivable — trade, net of allowance $944 and $1,025, respectively	48,824		50,137
Accrued unbilled revenues	19,299		26,694
Accounts receivable — other	16,238		13,101
Fuel, materials and supplies	48,800		48,811
Prepaid expenses and other	15,554		15,954
Unrealized gain in fair value of derivative contracts	9,153		2,469
Regulatory assets	10,229		7,743
	178,762		171,256

Noncurrent assets and deferred charges:
Regulatory assets	161,389		169,333
Goodwill	39,492		39,492
Unamortized debt issuance costs	8,511		8,826
Unrealized gain in fair value of derivative contracts	39		41
Other	3,395		4,163
	212,826		221,855
Total Assets	$	2,207,781	$	2,145,045

(Continued)

See accompanying Notes to Consolidated Financial Statements.

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THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS (UNAUDITED) (Continued)

	June 30, 2014		December 31, 2013
	($-000’s)
Capitalization and Liabilities
Common stock, $1 par value, 43,334,811 and 43,044,185 shares issued and outstanding, respectively	$	43,335	$	43,044
Capital in excess of par value	645,236		639,525
Retained earnings	77,626		67,554
Total common stockholders’ equity	766,197		750,123

Long-term debt (net of current portion):
Obligations under capital lease	4,023		4,167
First mortgage bonds and secured debt	637,597		637,578
Unsecured debt	101,691		101,683
Total long-term debt	743,311		743,428
Total long-term debt and common stockholders’ equity	1,509,508		1,493,551

Current liabilities:
Accounts payable and accrued liabilities	50,525		71,375
Current maturities of long-term debt	283		274
Short-term debt	52,500		4,000
Regulatory liabilities	11,869		5,681
Customer deposits	12,734		12,543
Interest accrued	6,592		6,352
Other current liabilities	2,894		299
Unrealized loss in fair value of derivative contracts	970		1,889
Taxes accrued	14,456		3,386
	152,823		105,799

Commitments and contingencies (Note 7)

Noncurrent liabilities and deferred credits:
Regulatory liabilities	132,241		132,012
Deferred income taxes	324,663		324,266
Unamortized investment tax credits	18,474		18,431
Pension and other postretirement benefit obligations	52,206		51,405
Unrealized loss in fair value of derivative contracts	2,096		2,799
Other	15,770		16,782
	545,450		545,695
Total Capitalization and Liabilities	$	2,207,781	$	2,145,045

See accompanying Notes to Consolidated Financial Statements.

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THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

	Six Months Ended
	June 30,
	2014			2013
	($-000’s)
Operating activities:
Net income	$	32,099		$	24,287
Adjustments to reconcile net income to cash flows from operating activities:
Depreciation and amortization including regulatory items	39,527			35,268
Pension and other postretirement benefit costs, net of contributions	5,154			7,174
Deferred income taxes and unamortized investment tax credit, net	3,513			12,096
Allowance for equity funds used during construction	(2,773		)	(1,393		)
Stock compensation expense	2,046			1,900
Loss on plant disallowance	—			2,409
Reverse gain on sale of assets	—			1,236
Non-cash (gain) on derivatives	(526		)	(67		)
Cash flows impacted by changes in:
Accounts receivable and accrued unbilled revenues	6,096			(7,140		)
Fuel, materials and supplies	11			8,138
Prepaid expenses, other current assets and deferred charges	(3,104		)	542
Accounts payable and accrued liabilities	(22,610		)	(20,639		)
Interest, taxes accrued and customer deposits	11,501			9,832
Asset retirement obligations	(1,234		)	—
Other liabilities and other deferred credits	(656		)	(2,638		)

Net cash provided by operating activities	69,044			71,005

Investing activities:
Capital expenditures — regulated	(94,783		)	(74,834		)
Capital expenditures and other investments — non-regulated	(784		)	(934		)
Restricted cash	(4,854		)	2,585

Net cash used in investing activities	(100,421		)	(73,183		)

Financing activities:
Proceeds from first mortgage bonds, net	—			150,000
Long-term debt issuance costs	—			(1,744		)
Redemption of senior notes	—			(98,000		)
Proceeds from issuance of common stock net of issuance costs	4,515			5,161
Net short-term borrowings/(repayments)	48,500			(24,000		)
Dividends	(22,027		)	(21,332		)
Other	(147		)	(432		)

Net cash provided by financing activities	30,841			9,653
Net increase/(decrease) in cash and cash equivalents	(536		)	7,475
Cash and cash equivalents at beginning of period	3,475			3,375
Cash and cash equivalents at end of period	$	2,939		$	10,850

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, 2013.

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, 2013.

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. 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, 2013 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 sheets (in thousands).

Regulatory Assets and Liabilities

	June 30, 2014			December 31, 2013
Regulatory Assets:
Current:
Under recovered fuel costs	$	3,556		$	1,411
Current portion of long-term regulatory assets	6,673			6,332
Regulatory assets, current	10,229			7,743
Long-term:
Pension and other postretirement benefits(1)	65,755			70,035
Income taxes	47,681			48,033
Deferred construction accounting costs(2)	16,050			16,275
Unamortized loss on reacquired debt	10,742			11,078
Unsettled derivative losses — electric segment	3,276			4,269
System reliability — vegetation management	5,803			7,539
Storm costs(3)	4,565			4,911
Asset retirement obligation	4,953			4,673
Customer programs	5,033			4,935
Unamortized loss on interest rate derivative	966			989
Deferred operating and maintenance expense	1,346			2,095
Under recovered fuel costs	1,219			—
Current portion of long-term regulatory assets	(6,673		)	(6,332		)
Other	673			833
Regulatory assets, long-term	161,389			169,333
Total Regulatory Assets	$	171,618		$	177,076

	June 30, 2014			December 31, 2013
Regulatory Liabilities:
Current:
Over recovered fuel costs	$	8,596		$	2,212
Current portion of long-term regulatory liabilities	3,273			3,469
Regulatory liabilities, current	11,869			5,681
Long-term:
Costs of removal	90,043			88,469
SWPA payment for Ozark Beach lost generation	18,034			19,405
Income taxes	11,581			11,677
Deferred construction accounting costs — fuel(4)	7,929			8,011
Unamortized gain on interest rate derivative	3,286			3,371
Pension and other postretirement benefits	2,324			2,177
Over recovered fuel costs	2,317			2,371
Current portion of long-term regulatory liabilities	(3,273		)	(3,469		)
Regulatory liabilities, long-term	132,241			132,012
Total Regulatory Liabilities	$	144,110		$	137,693

(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 $3.5 million at June 30, 2014.

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

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

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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 SPP Integrated Market 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 mechanism.

Risks and uncertainties affecting the determination of fair value include: market conditions in the energy industry, especially the effects of price volatility, regulatory and global political environments and requirements, fair value estimations on longer term contracts, the effectiveness of the derivative instrument in hedging the change in fair value of the hedged item, estimating underlying fuel demand and counterparty ability to perform. If we estimate that we have overhedged forecasted demand, the gain or loss on the overhedged portion will be recognized immediately as fuel and purchased power expense in our Consolidated Statement of Income and subject to our fuel adjustment mechanism.

As of June 30, 2014 and December 31, 2013, we have recorded the following assets and liabilities representing the fair value of derivative financial instruments, (in thousands):

		June 30,		December 31,
ASSET DERIVATIVES		2014		2013
Hedging instruments	Balance Sheet Classification	Fair Value		Fair Value
Natural gas contracts, gas segment	Current assets	$	2	$	35

Natural gas contracts, electric segment	Current assets	480		467
	Non-current assets and deferred charges - other	39		41
Transmission congestion rights, electric segment(1)	Current assets	8,671		1,967
Total derivatives assets		$	9,192	$	2,510

(1) We initially began acquiring transmission congestion rights during the fourth quarter of 2013. The first full year annual auction applicable to the June 1, 2014 through May 31, 2015 period occurred during the second quarter of 2014 causing an increase in derivative TCR positions.

		June 30,		December 31,
LIABILITY DERIVATIVES		2014		2013
Hedging instruments	Balance Sheet Classification
Natural gas contracts, gas segment	Current liabilities	$	3	$	8

Natural gas contracts, electric segment	Current liabilities	967		1,881
	Non-current liabilities and deferred credits	2,096		2,799
Total derivatives liabilities		$	3,066	$	4,688

Electric Segment

At June 30, 2014, approximately $0.5 million of unrealized net losses are applicable to natural gas financial instruments which will settle within the next twelve months.

The following tables set forth “mark-to-market” pre-tax gains/(losses) from non-designated derivative instruments for the electric segment for each of the periods ended June 30, (in thousands):

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Non-Designated Hedging Instruments - Due to	Balance Sheet Classification of	Amount of Gain / (Loss) Recognized on Balance Sheet
Regulatory Accounting	Gain / (Loss) on	Three Months Ended					Six Months Ended					Twelve Months Ended
Electric Segment	Derivative	2014		2013			2014		2013			2014		2013
Commodity contracts	Regulatory (assets)/liabilities	$	401	$	(2,852	)	$	2,159	$	(432	)	$	2,252	$	(1,052	)

Transmission congestion rights	Regulatory (assets)/liabilities	11,024		—			11,652		—			13,619		—
Total Electric Segment		$	11,425	$	(2,852	)	$	13,811	$	(432	)	$	15,871	$	(1,052	)

Non-Designated Hedging Instruments - Due to	Statement of Income Classification of	Amount of Gain / (Loss) Recognized in Income on Derivative
Regulatory Accounting	Gain / (Loss) on	Three Months Ended					Six Months Ended					Twelve Months Ended
Electric Segment	Derivative	2014		2013			2014		2013			2014			2013
Commodity contracts	Fuel and purchased power expense	$	160	$	(407	)	$	915	$	(521	)	$	(1,289	)	$	(4,565	)

Transmission congestion rights	Fuel and purchased power expense	4,422		—			5,222		—			5,303			—
Total Electric Segment		$	4,582	$	(407	)	$	6,137	$	(521	)	$	4,014		$	(4,565	)

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

As of June 30, 2014, the following volumes and percentage of our anticipated volume of natural gas usage for our electric operations for the remainder of 2014 and for the next four years are shown below at the following average prices per Dekatherm (Dth).

			Dth Hedged
Year	% Hedged		Physical	Financial	Average Price
Remainder 2014	66	%	1,230,000	2,990,000	$	4.543
2015	50	%	300,000	4,510,000	$	4.470
2016	43	%	1,976,000	2,100,000	$	4.103
2017	17	%	420,900	1,300,000	$	4.219
2018	6	%	—	500,000	$	4.516

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

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

At June 30, 2014, the following transmission congestion rights (TCR) have been obtained to hedge congestion risk in the SPP Integrated Market (dollars in thousands):

Year	Monthly MWH Hedged	$ Value
2014	4,354	$	8,671

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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 forward contracts and (3) purchasing financial derivative contracts. We target to have 95% of our storage capacity full by November 1 for the upcoming winter heating season. As the winter progresses, gas is withdrawn from storage to serve our customers. As of June 30, 2014, we had 0.8 million Dths in storage on the three pipelines that serve our customers. This represents 39% of our storage capacity.

The following table sets forth our long-term hedge strategy of mitigating price volatility for our customers by hedging a minimum of expected gas usage for the current winter season and the next two winter seasons by the beginning of the Actual Cost Adjustment (ACA) year at September 1 and illustrates our hedged position as of June 30, 2014 (in thousands):

Season	Minimum % Hedged	Dth Hedged Financial	Dth Hedged Physical	Dth in Storage	Actual % Hedged
Current	50%	120,000		785,809	28	%
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 June 30, (in thousands).

Non-Designated Hedging	Balance Sheet Classification of	Amount of Gain/(Loss) Recognized on Balance Sheet
Instruments Due to Regulatory	Gain / (Loss) on	Three Months Ended						Six Months Ended						Twelve Months Ended
Accounting - Gas Segment	Derivative	2014			2013			2014			2013			2014		2013
Commodity contracts	Regulatory (assets)/liabilities	$	(1	)	$	(71	)	$	(1	)	$	(18	)	$	137	$	12
Total - Gas Segment		$	(1	)	$	(71	)	$	(1	)	$	(18	)	$	137	$	12

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 liability position on June 30, 2014 and have posted no collateral in the normal course of business. Amounts reported as margin deposit assets represent our funds held on deposit for our NYMEX contracts with our broker and other financial contracts with other counterparties that resulted from us exceeding agreed-upon credit limits established by the counterparties. The following table depicts our margin deposit assets at June 30, 2014 and December 31, 2013. There were no margin deposit liabilities at these dates.

(in millions)	June 30, 2014		December 31, 2013
Margin deposit assets	$	3.5	$	5.2

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

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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 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 June 30, 2014 and December 31, 2013, 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 Integrated Market, 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 June 30, 2014 and December 31, 2013.

	Fair Value Measurements at Reporting Date Using
($ in 000’s) Description	Assets/(Liabilities) at Fair Value			Quoted Prices in Active Markets for Identical Liabilities (Level 1)			Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	June 30, 2014
Derivative assets	$	9,192		$	521		$	8,671	$	—
Derivative liabilities	$	(3,066	)	$	(3,066	)	$	—	$	—

	December 31, 2013
Derivative assets	$	2,510		$	543		$	1,967	$	—
Derivative liabilities	$	(4,688	)	$	(4,688	)	$	—	$	—

*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

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classified as Level 2 in the fair value hierarchy as they are valued based on market rates for similar market transactions.

The carrying amount of our total long-term debt exclusive of capital leases at June 30, 2014 was $739 million and at December 31, 2013 was $739 million. The fair market value at June 30, 2014 was approximately $767 million as compared to approximately $715 million at December 31, 2013. 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 June 30, 2014 or that will be realizable in the future.

Note 6— Financing

We have an unsecured revolving credit facility of $150 million in place through January 17, 2017. The facility is used for working capital, general corporate purposes and to back-up our use of commercial paper. This facility requires our total indebtedness to be less than 62.5% of our total capitalization at the end of each fiscal quarter and our EBITDA (defined as net income plus interest, taxes, depreciation and amortization) to be at least two times our interest charges for the trailing four fiscal quarters at the end of each fiscal quarter. Failure to maintain these ratios will result in an event of default under the credit facility and will prohibit us from borrowing funds thereunder. As of June 30, 2014, we are in compliance with these ratios. Our total indebtedness is 51.0% of our total capitalization as of June 30, 2014 and our EBITDA is 5.9 times our interest charges. This credit facility is also subject to cross-default if we default on in excess of $10 million in the aggregate on our other indebtedness. This arrangement does not serve to legally restrict the use of our cash in the normal course of operations. There were no outstanding borrowings under this agreement at June 30, 2014, however, $52.5 million was used to back up our outstanding commercial paper.

Note 7— Commitments and Contingencies

Legal Proceedings

We are a party to various claims and legal proceedings arising out of the normal course of our business. 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 our opinion, 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 June 30, 2014 (in millions).

	Firm physical gas and transportation contracts		Coal and coal transportation contracts

July 1, 2014 through December 31, 2014	$	15.0	$	8.0
January 1, 2015 through December 31, 2016	41.6		33.6
January 1, 2017 through December 31, 2018	33.2		25.5
January 1, 2019 and beyond	49.5		11.5

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

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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 June 30, 2014, 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 capacity from Plum Point. Commitments under this agreement are approximately $292.4 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 MPSC on July 1, 2013. While it is not currently our intention to exercise this option in 2015, we will continue to evaluate this purchase option through the exercise date as well as explore other options with the purchase power agreement holder, Plum Point Energy Associates (PPEA), related to the timing of this option.

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 contract, which began on December 15, 2005, with Elk River Windfarm, LLC, owned by IBERDROLA RENEWABLES, Inc., to purchase the energy generated at the 150-megawatt Elk River Windfarm located in Butler County, Kansas. 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.

Payments for these wind agreements are recorded as purchased power expenses, and, because of the contingent nature of these payments, are not included in our operating lease obligations.

New Construction

We have in place a contract with a third party vendor to complete environmental retrofits at our Asbury plant. The retrofits will include the installation of a pulse-jet fabric filter (baghouse), circulating dry scrubber and powder activated carbon injection system. This equipment will enable us to comply with the Mercury and Air Toxics Standard (MATS). The addition of this air quality control equipment is expected to be completed by early 2015 at a cost ranging from $112.0 million to $130.0 million, excluding AFUDC. Construction costs through June 30, 2014 were $97.4 million for the project to date, excluding AFUDC.

We also 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 will include 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 Kansas Department of Health and Environment on July 11, 2013. This conversion is currently scheduled to be completed in 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

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expenditure plan. Construction costs, consisting of pre-engineering, site preparation activities and contract costs incurred project to date through June 30, 2014 were $42.4 million, excluding AFUDC.

See “Environmental Matters” below for more information on both of these projects.

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 June 30, 2014.

Environmental Matters

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

Electric Segment

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 are taking actions to implement our compliance plan and strategy (Compliance Plan). The Mercury Air Toxic Standards (MATS) and the Clean Air Interstate Rule (CAIR) and its subsequent replacement rule, both regulations 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 require full compliance by April 16, 2015 (with flexibility for extensions for reliability reasons). The Cross State Air Pollution Rule (CSAPR — formerly the Clean Air Transport Rule, or CATR) was first proposed by the EPA in July 2010 as a replacement of CAIR and was set to take effect on January 1, 2012. CSAPR was stayed by the D.C Circuit Court of Appeals in late December 2011, then vacated by court order in August 2012. On April 29, 2014, the U.S. Supreme Court (the Court) reversed the D.C Circuit Court of Appeals judgment, and remanded the case back to the D.C. Circuit Court for further proceedings consistent with the Court’s opinion. In light of the Supreme Court’s decision upholding the EPA’s approach to implementing the good neighbor provision in CSAPR, on June 26, 2014, the EPA moved to lift the stay entered in late December 2011. However, CAIR will remain in effect until proceedings become final. We anticipate compliance costs associated with the MATS and CAIR (or its subsequent replacement) regulations to be recoverable in our rates.

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Our Compliance Plan largely follows the preferred plan presented in our Integrated Resource Plan (IRP), filed in mid-2013 with the MPSC. As described above under New Construction, we are in the process of installing a scrubber, fabric filter, and powder activated carbon injection system at our Asbury plant. The addition of this air quality control equipment is expected to be completed by early 2015. 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.

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 conversion of Riverton Unit 12, a simple cycle combustion turbine, to a combined cycle unit. This conversion is currently scheduled to be completed in mid-2016. Once our Asbury and Riverton projects are completed, our generating fleet aggregate emissions will be in compliance with CSAPR’s emission limits as originally proposed. However, the current version of CSAPR is likely to be revised to be consistent with the April 29, 2014 U.S. Supreme Court decision.

See “New Construction” above for project costs for both of these projects.

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. Currently, NOx emissions are regulated by the CAIR and National Ambient Air Quality Standard (NAAQS) rules for ozone (discussed below). SO2 emissions are currently regulated by the Title IV Acid Rain Program and the CAIR.

CAIR:

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

SO2 allowance allocations under the Title IV Acid Rain Program are used for compliance in the CAIR SO2 Program. The alternate plans in our Integrated Resource Plan (IRP) assumed costs for other emissions such as SO2, NOx and mercury. In the most recent five-year business plan 2014-2018, which assumes normal operations, we do not anticipate the need to purchase any allowances for these pollutants. However, if economically beneficial, we could purchase minimal quantities of allowances in the future.

Based on the April 29, 2014 U.S. Supreme Court decision, the current version of CSAPR (CAIR’s replacement) is likely to be revised to be consistent with the court’s opinion.

Mercury Air Toxics Standard (MATS):

As described above, the MATS standard became effective in April 2012, and requires compliance by April 2015 (with flexibility for extensions for reliability reasons). For all existing and new coal-fired electric utility steam generating units (EGUs), the MATS standard will be phased in over three years, and allows states the ability to give facilities a fourth year to comply. On March 28, 2013, the EPA finalized updates to certain emission limits for new power plants under the MATS. The new standards affect only new coal and oil-fired power plants that will be built in the future. The update does not change the final emission limits or other requirements for existing power plants.

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.

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In January 2013, the EPA finalized the revised PM 2.5 primary annual standard at 12 ug/m(3) (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 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 is expected to be proposed by the EPA in early 2015 and the final rule is expected in November 2015.

Greenhouse Gases (GHGs):

As the EPA began to prepare for future regulations, GHG emissions have been reported for several years under the Mandatory GHG Reporting Rule. EDE and EDG’s GHG emissions for each year, including 2013, have been reported to the EPA as required.

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 comment period ended May 9, 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 are currently being undertaken at our Asbury facility and at the Riverton facility with the conversion of simple cycle Unit 12 to combined cycle.

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: making fossil fuel power plants more efficient; 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 June 1, 2015. Each state must submit its initial plan by June 30, 2016 with additional time available by request until June 2017 for a single state or June 2018 for a multi-state approach. Currently, state and industry representatives including Empire are collaborating to evaluate future impacts of the rule as proposed by the EPA.

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.

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 announced its final rule on May 19, 2014 but has not established an

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effective date of the regulation. We expect the regulations to have a limited impact at Riverton. The retirement of unit 8 is 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. Our new Iatan Unit 2 and Plum Point Unit 1 are covered by the proposed regulation, but were constructed with cooling towers, the proposed Best Technology Available. We expect them to be unaffected or minimally affected by the final rule.

Surface Impoundments

We own and maintain coal ash impoundments located at our Riverton and Asbury Power Plants. Additionally, we own a 12% interest in a coal ash impoundment at the Iatan Generating Station and a 7.52% interest in a coal ash impoundment at Plum Point. 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. All of our coal ash impoundments are compliant with existing state and federal regulations.

In June 2010, the EPA proposed to regulate coal combustion residuals (CCRs) under the Federal Resource Conservation and Recovery Act (RCRA). In the proposal, the EPA presented two options: (1) regulation of CCR under RCRA subtitle C as a hazardous waste and (2) regulation of CCR under RCRA subtitle D as a non-hazardous waste. It is anticipated that the final regulation will be published in late 2014. We expect compliance with either option to result in the need to construct a new landfill and the conversion of existing ash handling from a wet to a dry system(s) at a potential cost of up to $15 million at our Asbury Power Plant. This preliminary estimate will likely change based on the final CCR rule and its requirements. We expect resulting costs to be recoverable in our rates.

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).

We have received preliminary permit approval in Missouri for a new utility waste landfill adjacent to the Asbury plant. Our Detailed Site Investigation (DSI) will be finalized in late 2014. Receipt of the final construction permit for the waste landfill is expected in late 2015.

Renewable Energy

Missouri regulations currently require 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 with Cloud County Windfarm, LLC, located in Cloud County, Kansas, and Elk River Windfarm, LLC, located in Butler County, Kansas. The regulations also require that 2% of the energy from renewable energy sources must be solar; however, we are exempted by statute from that solar requirement. As noted in our Annual Report on Form 10-K for the year ended December 31, 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 notice of appeal seeking review by the Missouri Supreme Court. The case has been briefed by the parties and is awaiting action by the Court.

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

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Windfarm, LLC, located in Cloud County, Kansas and Elk River Windfarm, LLC, located in Butler County, Kansas.

Note 8 — Retirement Benefits

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

	Three months ended June 30,
	Pension Benefits						SERP						OPEB
	2014			2013			2014			2013			2014			2013
Service cost	$	1,627		$	1,859		$	29		$	52		$	607		$	715
Interest cost	2,733			2,523			87			94			1,081			922
Expected return on plan assets	(3,322		)	(3,089		)	—			—			(1,197		)	(1,077		)
Amortization of prior service cost (1)	105			133			(2		)	(2		)	(253		)	(253		)
Amortization of net actuarial loss (1)	1,649			2,632			105			180			229			481
Net periodic benefit cost	$	2,792		$	4,058		$	219		$	324		$	467		$	788

	Six months ended June 30,
	Pension Benefits						SERP						OPEB
	2014			2013			2014			2013			2014			2013
Service cost	$	3,254		$	3,727		$	58		$	67		$	1,214		$	1,470
Interest cost	5,467			5,031			173			157			2,161			1,913
Expected return on plan assets	(6,644		)	(6,214		)	—			—			(2,393		)	(2,176		)
Amortization of prior service cost (1)	209			266			(4		)	(4		)	(506		)	(505		)
Amortization of net actuarial loss (1)	3,298			5,223			211			284			457			1,131
Net periodic benefit cost	$	5,584		$	8,033		$	438		$	504		$	933		$	1,833

	Twelve months ended June 30,
	Pension Benefits						SERP						OPEB
	2014			2013			2014			2013			2014			2013
Service cost	$	6,981		$	6,732		$	125		$	104		$	2,684		$	2,742
Interest cost	10,498			10,187			330			308			4,074			3,885
Expected return on plan assets	(12,858		)	(12,372		)	—			—			(4,569		)	(4,229		)
Amortization of prior service cost (1)	475			531			(8		)	(8		)	(1,011		)	(1,011		)
Amortization of net actuarial loss (1)	8,520			9,259			495			520			1,588			1,858
Net periodic benefit cost	$	13,616		$	14,337		$	942		$	924		$	2,766		$	3,245

(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 $12.0 million during 2014, of which we have made contributions of approximately $3.0 million as of July 15, 2014. 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 $3.0 million during 2014, of which we have made contributions of approximately $1.2 million as of July 1, 2014. The actual minimum funding requirements will be determined based on the results of the actuarial valuations.

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Note 9— Stock-Based Awards and Programs

Our performance-based restricted stock awards, stock options 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 2014 (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 associated with issued, unvested awards of $1.3 million as of June 30, 2014.

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

	Three Months Ended				Six Months Ended				Twelve Months Ended
	2014		2013		2014		2013		2014		2013
Compensation Expense	$	518	$	420	$	1,868	$	1,711	$	2,734	$	2,376
Tax Benefit Recognized	187		146		690		622		997		844

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 June 30, 2014 and 2013 and changes during the six months ended June 30, 2014 and 2013 were as follows:

	2014				2013
	Number of shares		Weighted Average Grant Date Price		Number of shares		Weighted Average Grant Date Price

Outstanding at January 1,	47,200		$	21.39	33,900		$	20.25
Granted	27,000		$	22.40	26,300		$	21.36
Awarded	0		$	21.84	(4,460	)	$	18.36
Not Awarded	(10,900	)	$	21.84	(8,540	)	$	18.36

Nonvested at June 30,	63,300		$	21.74	47,200		$	21.39

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.

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A summary of time vested restricted stock activity under the plan for 2013 and 2014 is presented in the table below:

	2014				2013
			Weighted			Weighted
	Number of		Average Fair		Number of	Average Fair
	shares		Market Value		shares	Market Value
Outstanding at January 1,	24,900		$	22.68	3,300	$	20.38
Granted	22,600		22.40		21,600	21.36
Vested	710		24.29		—	—
Distributed	(3,300	)	22.98
Forfeited	(2,490	)	—		—	—
Vested but not distributed	(710	)	—		—	—
Outstanding at end of period	41,710		$	24.32	24,900	$	22.40

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

Stock Options

Stock option grants vest upon satisfaction of service conditions. The cost of the awards is generally recognized over the requisite (explicit) service period. The fair value of the outstanding options was estimated as of June 30, 2014 and 2013, under a Black-Scholes methodology.

A summary of option activity under the plan during the quarters ended June 30, 2014 and June 30, 2013 is presented below:

	2014			2013
		Weighted Average			Weighted Average
	Options	Exercise Price		Options	Exercise Price

Outstanding at January 1,	112,500	$	23.27	163,300	$	23.15
Granted	—	—		—	—
Exercised June 30,	67,000	$	23.98	40,200	$	21.66
Outstanding at June 30,	45,500	$	23.81	123,100	$	23.19
Exercisable at June 30,	45,500	$	23.81	123,100	$	23.19

Employee Stock Purchase Plan

Our Employee Stock Purchase Plan (ESPP) permits the grant to eligible employees of options to purchase common stock at 90% of the lower of market value at date of grant or at date of exercise. The lookback feature of this plan is valued at 90% of the Black-Scholes methodology plus 10% of the maximum subscription price. As of June 30, 2014, there were 70,838 shares available for issuance in this plan. On May 1, 2014, our shareholders approved an amended and restated ESPP to reserve an additional 750,000 shares.

	2014		2013
Subscriptions outstanding at June 30	58,627		62,793
Maximum subscription price(1)	$	21.43	$	19.58
Shares of stock issued	56,942		68,099
Stock issuance price	$	19.58	$	17.95

(1) Stock will be issued on the closing date of the purchase period, which runs from June 1, 2014 to May 31, 2015.

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

	2014	2013
Weighted average fair value of grants at June 30	$3.07	$2.78
Risk-free interest rate	0.10%	0.14%
Expected dividend yield	4.30%	4.60%
Expected volatility	14.00%	14.00%
Expected life in months	12	12
Grant Date	6/2/14	6/1/13

Note 10- Regulated Operating Expenses

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

	Three Months Ended		Three Months Ended		Six Months Ended		Six Months Ended		Twelve Months Ended		Twelve Months Ended
	2014		2013		2014		2013		2014		2013
Electric transmission and distribution expense	$	6,878	$	5,950	$	13,676	$	10,979	$	24,560	$	19,690
Natural gas transmission and distribution expense	558		577		1,232		1,122		2,608		2,250
Power operation expense (other than fuel)	4,021		4,367		8,012		8,011		15,644		15,953
Customer accounts and assistance expense	2,884		2,619		5,720		5,198		11,701		10,391
Employee pension expense (1)	2,602		2,757		5,228		5,399		10,565		10,505
Employee healthcare plan (1)	2,607		2,408		4,332		5,195		9,327		10,458
General office supplies and expense	3,185		3,163		7,376		6,592		13,635		12,093
Administrative and general expense	3,438		3,603		7,664		7,918		14,546		15,217
Allowance for uncollectible accounts	1,329		1,044		2,101		1,790		3,976		3,483
Regulatory reversal of gain on sale of assets	—		—		—		1,236		—		1,236
Miscellaneous expense	107		159		225		344		553		687
Total	$	27,609	$	26,647	$	55,566	$	53,784	$	107,115	$	101,963

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

Note 11— Segment Information

We operate our business as three segments: electric, gas and other. As part of our electric segment, we also provide water service to three towns in Missouri. The Empire District Gas Company is our wholly owned subsidiary formed to provide gas distribution service in Missouri. The other segment consists of our non-regulated businesses which is primarily our fiber optics business.

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

($-000’s)	For the quarter ended June 30, 2014
Statement of Income Information	Electric		Gas			Other		Eliminations			Total
Revenues	$	140,767	$	6,989		$	2,346	$	(320	)	$	149,782
Depreciation and amortization	16,791		913			453		—			18,157
Federal and state income taxes	6,331		(90		)	408		—			6,649
Operating income	18,185		624			693		—			19,502
Interest income	—		7			5		(9		)	3
Interest expense	9,454		963			—		(9		)	10,408
Income from AFUDC (debt and equity)	2,301		51			—		—			2,352
Net income	10,826		(295		)	663		—			11,194

Capital Expenditures	$	44,911	$	1,249		$	382	—			$	46,542

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	For the quarter ended June 30, 2013
	Electric		Gas			Other		Eliminations			Total
($-000’s)
Statement of Income Information
Revenues	$	127,026	$	7,777		$	1,991	$	(148	)	$	136,646
Depreciation and amortization	16,205		927			503		—			17,635
Federal and state income taxes	6,948		(129		)	230		—			7,049
Operating income	19,994		744			372		—			21,110
Interest income	3		34			2		(29		)	10
Interest expense	9,557		976			—		(29		)	10,504
Income from AFUDC (debt and equity)	1,331		8			—		—			1,339
Net income	11,498		(214		)	374		—			11,658

Capital Expenditures	$	36,535	$	1,463		$	502	—			$	38,500

	For the six months ended June 30, 2014
	Electric		Gas		Other		Eliminations			Total
($-000’s)
Statement of Income Information
Revenues	$	293,856	$	31,598	$	4,641	$	(640	)	$	329,455
Depreciation and amortization	33,366		1,824		907		—			36,097
Federal and state income taxes	16,578		1,358		833		—			18,769
Operating income	43,711		3,899		1,380		—			48,990
Interest income	32		19		8		(15		)	44
Interest expense	18,821		1,926		—		(15		)	20,732
Income from AFUDC (debt and equity)	4,267		76		—		—			4,343
Net income	28,710		2,035		1,354		—			32,099

Capital Expenditures	$	91,614	$	4,422	$	839	—			$	96,875

	For the six months ended June 30, 2013
	Electric		Gas		Other		Eliminations			Total
($-000’s)
Statement of Income Information
Revenues	$	255,788	$	28,270	$	4,024	$	(296	)	$	287,786
Depreciation and amortization	30,887		1,851		998		—			33,736
Federal and state income taxes	12,943		1,076		512		—			14,531
Operating income	38,509		3,639		820		—			42,968
Interest income	497		105		7		(92		)	517
Interest expense	18,893		1,953		—		(92		)	20,754
Income from AFUDC (debt and equity)	2,161		9		—		—			2,170
Net income	21,721		1,735		831		—			24,287

Capital Expenditures	$	73,070	$	2,196	$	942	—			$	76,208

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	For the twelve months ended June 30, 2014
	Electric		Gas		Other		Eliminations			Total
($-000’s)
Statement of Income Information
Revenues	$	574,481	$	53,369	$	9,764	$	(1,616	)	$	635,998
Depreciation and amortization	66,138		3,682		1,848		—			71,668
Federal and state income taxes	38,113		1,766		1,852		—			41,731
Operating income	96,187		6,453		3,045		—			105,685
Interest income	71		29		9		(17		)	92
Interest expense	37,612		3,862		—		(17		)	41,457
Income from AFUDC (debt and equity)	8,016		98		—		—			8,114
Net income	65,592		2,655		3,010		—			71,257

Capital Expenditures	$	175,445	$	6,645	$	2,285	—			$	184,375

	For the twelve months ended June 30, 2013
	Electric		Gas		Other		Eliminations			Total
($-000’s)
Statement of Income Information
Revenues	$	522,624	$	46,632	$	7,443	$	(592	)	$	576,107
Depreciation and amortization	58,869		3,669		1,642		—			64,180
Federal and state income taxes	33,277		1,406		1,047		—			35,730
Operating income	89,876		6,055		1,684		—			97,615
Interest income	1,155		262		13		(243		)	1,187
Interest expense	37,558		3,905		—		(243		)	41,220
Income from AFUDC (debt and equity)	3,811		18		—		—			3,829
Net Income	55,487		2,267		1,702		—			59,456

Capital Expenditures	$	149,619	$	4,198	$	2,003	—			$	155,820

	As of June 30, 2014
	Electric		Gas(1)		Other		Eliminations			Total
($-000’s)
Balance Sheet Information
Total assets	$	2,098,131	$	122,304	$	31,965	$	(44,619	)	$	2,207,781

(1) Includes goodwill of $39,492.

	As of December 31, 2013
	Electric		Gas(1)		Other		Eliminations			Total
($-000’s)
Balance Sheet Information
Total assets	$	2,034,234	$	123,736	$	31,306	$	(44,231	)	$	2,145,045

(1) Includes goodwill of $39,492.

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Note 12— Income Taxes

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

	Three Months Ended						Six-Months Ended						Twelve Months Ended
	2014			2013			2014			2013			2014			2013
Consolidated provision for income taxes	$	6.6		$	7.0		$	18.8		$	14.5		$	41.7		$	35.7
Consolidated effective federal and state income tax rates	37.3		%	37.7		%	36.9		%	37.4		%	36.9		%	37.5		%

The effective income tax rate for the three, six and twelve month periods ended June 30, 2014 is lower than comparable periods in 2013 primarily due to higher equity AFUDC income in 2014 compared with 2013.

We do not have any unrecognized tax benefits as of June 30, 2014. 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.

In 2010, we received $17.7 million of investment tax credits based on our investment in Iatan 2. We utilized $0.7 million of these credits when preparing our 2012 tax return. We expect to utilize approximately $10.7 million of these credits on our 2013 tax return. We expect to use the remaining credits on our 2014 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.

The American Taxpayer Relief Act of 2012 (the “Act”) was signed into law on January 2, 2013. The Act restored several expired business tax provisions, including bonus depreciation for 2013. Our 2014 tax payments are expected to be higher than 2013 due to the expiration of bonus depreciation. However, we expect to utilize investment tax credits noted above to partially offset the 2014 payments.

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. 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 June 30, 2014, our gross operating revenues were derived as follows:

Electric segment sales*	90.3	%
Gas segment sales	8.4
Other segment sales	1.3

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

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Earnings

The following table represents our basic and diluted earnings per weighted average share of common stock for the applicable periods ended June 30 (in dollars):

	Three Months Ended				Six Months Ended				Twelve Months Ended
	2014		2013		2014		2013		2014		2013

Basic earnings per weighted average share of common stock	$	0.26	$	0.27	$	0.74	$	0.57	$	1.66	$	1.40
Diluted earnings per weighted average share of common stock	$	0.26	$	0.27	$	0.74	$	0.57	$	1.65	$	1.40

Rate changes, primarily the June 2013 and June 2014 rate increases for our wholesale on-system customers, increased revenues during the second quarter of 2014 as compared to the second quarter of 2013. Increases in electric customer rates resulting from the April 1, 2013 Missouri rate increase positively impacted electric results for the six months ended and twelve months ended periods ended June 30, 2014 as compared to the same periods in 2013. However, increased regulatory operating expenses, depreciation and amortization expenses and property and other tax expenses, offset the impact of increased customer rates in all periods. Increased AFUDC due to higher levels of construction activity positively impacted results during each period presented.

The six months ended and twelve months ended June 30, 2014 periods were also positively impacted by favorable weather as compared to the same periods in 2013.

The table below sets forth a reconciliation of basic and diluted earnings per share between the three months, six months and twelve months ended June 30, 2013 and June 30, 2014, 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 June 30.

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

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 margins as electric revenues less fuel and purchased power costs. We define gas gross margins as gas operating revenues less cost of gas in rates. 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 earnings per share determined in accordance with GAAP as a measure of operating performance or any other measure of financial performance presented in accordance with GAAP. Management compensates for the limitations of using non-GAAP financial measures by using them to supplement GAAP results to provide a more complete understanding of the factors and trends affecting the business than GAAP results alone.

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	Three Months Ended			Six Months Ended			Twelve Months Ended
Earnings Per Share — 2013	$	0.27		$	0.57		$	1.40

Revenues
Electric segment	$	0.20		$	0.56		$	0.76
Gas segment	(0.01		)	0.05			0.10
Other segment	0.00			0.00			0.02
Total Revenue	0.19			0.61			0.88
Electric fuel and purchased power	(0.18		)	(0.33		)	(0.33		)
Cost of natural gas sold and transported	0.01			(0.04		)	(0.08		)
Gross Margin	0.02			0.24			0.47

Operating — electric segment	(0.01		)	(0.02		)	(0.06		)
Operating —gas segment	0.00			0.00			(0.01		)
Maintenance and repairs	(0.02		)	(0.04		)	(0.06		)
Depreciation and amortization	(0.01		)	(0.03		)	(0.11		)
Loss on plant disallowance	0.00			0.03			0.03
Other taxes	(0.01		)	(0.03		)	(0.06		)
AFUDC	0.02			0.03			0.06
Change in effective income tax rates	0.00			0.01			0.02
Other income and deductions	0.00			(0.01		)	0.00
Dilutive effect of additional shares issued	0.00			(0.01		)	(0.02		)
Earnings Per Share — 2014	$	0.26		$	0.74		$	1.66

Recent Activities

Regulatory Matters

On May 28, 2014, we filed a Notice of Intended Case Filing with the Missouri Public Service Commission (MPSC) of our intentions to file an electric rate case in Missouri as early as August 1, 2014.

On December 3, 2013, we filed a request with the Arkansas Public Service Commission (APSC) for changes in rates for our Arkansas electric customers. We were seeking an annual increase in total revenue of approximately $2.2 million, or approximately 18%. The rate increase was requested to recover costs incurred to ensure continued reliable service for our customers, including capital investments, operating systems replacement costs and ongoing increases in other operation and maintenance expenses and capital costs. We reached an agreement with the parties in the case for an increase of $1.375 million, or approximately 11%. On May 20, 2014, we filed a settlement agreement with the APSC. The APSC held a hearing on the settlement agreement on July 22, 2014.

For additional information, see “Rate Matters” below.

Day-Ahead Market

The Southwest Power Pool (SPP) regional transmission organization (RTO) implemented a Day-Ahead Market, or Integrated Marketplace, on March 1, 2014 in which market participants buy and sell wholesale energy and reserves in both day-ahead and real-time markets through the operation of a single, consolidated SPP balancing authority. Through the Integrated Marketplace, the SPP is able to coordinate next-day generation across the region and provide participants, including Empire, with greater access to reserve energy. See “— Markets and Transmission” below for more information.

Integrated Resource Plan

We filed our Integrated Resource Plan (IRP) with the MPSC on July 1, 2013. The IRP analysis of future loads and resources is normally conducted once every three years. Our IRP supports our Compliance Plan discussed in Note 7 of “Notes to Consolidated Financial Statements” under Item 1. On March 12, 2014, the MPSC issued an order approving our IRP, effective March 12, 2014.

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RESULTS OF OPERATIONS

The following discussion analyzes significant changes in the results of operations for the three month, six month and twelve month periods ended June 30, 2014, compared to the same periods ended June 30, 2013.

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

	Three Months Ended						Six Months Ended				Twelve Months Ended
	2014			2013			2014		2013		2014		2013

Electric	$	10.8		$	11.5		$	28.7	$	21.7	$	65.6	$	55.5
Gas	(0.3		)	(0.2		)	2.0		1.8		2.7		2.3
Other	0.7			0.4			1.4		0.8		3.0		1.7
Net income	$	11.2		$	11.7		$	32.1	$	24.3	$	71.3	$	59.5

Electric Segment

Gross Margin

The table below represents our electric gross margins for the applicable periods ended June 30 (dollars in millions):

	Three Months Ended				Six Months Ended				Twelve Months Ended
	2014		2013		2014		2013		2014		2013

Electric segment revenues	$	140.8	$	127.0	$	293.8	$	255.8	$	574.5	$	522.6
Fuel and purchased power	54.4		42.0		109.9		87.3		198.0		175.4
Electric segment gross margins	$	86.4	$	85.0	$	183.9	$	168.5	$	376.5	$	347.2

As shown in the table above, electric segment gross margin increased approximately $1.4 million during the second quarter of 2014 as compared to the second quarter of 2013, mainly due to increased rates for our wholesale electric customers.

The electric gross margin increased approximately $15.4 million for the six months ended June 30, 2014 as compared to the same period in 2013, mainly due to increased demand resulting from colder weather in the first quarter of 2014 as compared to the same period in 2013 and to increased rates for our Missouri electric customers.

The electric gross margin increased approximately $29.3 million for the twelve months ended June 30, 2014 as compared to the same period in 2013, due to a full twelve months of increased Missouri electric rates that were effective April 1, 2013, increased demand resulting from the favorable 2013-2014 heating season and an increase in average electric customer counts.

Sales and Revenues

Electric operating revenues comprised approximately 94.0% of our total operating revenues during the second quarter of 2014.

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 June 30, were as follows (in millions):

	kWh Sales
	Second	Second			6 Months	6 Months			12 Months	12 Months
	Quarter	Quarter	%		Ended	Ended	%		Ended	Ended	%
Customer Class	2014	2013	Change(1)		2014	2013	Change(1)		2014	2013	Change(1)
Residential	369.8	387.3	(4.5	)%	1,011.3	958.3	5.5	%	1,989.6	1,943.5	2.4	%
Commercial	381.9	377.0	1.3		770.5	736.7	4.6		1,575.5	1,557.7	1.1
Industrial	261.7	264.4	(1.0	)	498.8	505.0	(1.2	)	1,009.3	1,022.1	(1.3	)
Wholesale on-system	80.6	83.9	(4.0	)	164.7	168.4	(2.2	)	339.4	348.0	(2.5	)
Other(2)	30.0	31.5	(4.7	)	65.2	64.5	1.1		130.1	128.4	1.3
Total on-system sales	1,124.0	1,144.1	(1.8	)	2,510.5	2,432.9	3.2		5,043.9	4,999.7	0.9

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

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

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KWh sales for our on-system customers decreased 1.8% during the quarter ended June 30, 2014, as compared to the same period in 2013, despite more temperate weather in the second quarter of 2014. Contributing to the decreased sales were volumetric changes related to weather variability as we transition from heating to cooling season, customer usage and other related factors. KWh sales for our residential customers, which are more weather sensitive, decreased 4.5%. Commercial sales increased 1.3%.

KWh sales for our on-system customers increased 3.2% during the six months ended June 30, 2014, as compared to the same period in 2013, primarily due to increased demand resulting from colder weather in the first quarter of 2014. Residential and commercial kWh sales increased primarily due to the colder weather in the first quarter of 2014.

KWh sales for our on-system customers increased 0.9% during the twelve months ended June 30, 2014, as compared to the same period in 2013, due to increased customer counts and increased demand resulting from the favorable 2013-2014 heating season, partially offset by the milder 2013 third quarter weather. Residential and commercial kWh sales increased primarily due to the colder weather in the first quarter of 2014 and increased customer counts.

Industrial sales decreased 1.0%, 1.2% and 1.3% during the quarter, six month and twelve month periods ended June 30, 2014, respectively, due to reduced usage by several large industrial customers.

The amounts and percentage changes from the prior periods in electric segment operating revenues by major customer class for on-system and off-system sales for the applicable periods ended June 30 were as follows (dollars in millions):

	Electric Segment Operating Revenues
	Second		Second				6 Months		6 Months				12 Months		12 Months
	Quarter		Quarter		%		Ended		Ended		%		Ended		Ended		%
Customer Class	2014		2013		Change(1)		2014		2013		Change(1)		2014		2013		Change(1)
Residential	$	47.0	$	47.9	(1.9	)%	$	119.2	$	109.2	9.2	%	$	237.7	$	222.2	7.0	%
Commercial	42.1		41.0		2.7		82.2		75.8		8.4		168.8		158.8		6.3
Industrial	21.4		21.1		1.4		39.4		38.2		3.1		81.7		78.2		4.5
Wholesale on-system	5.7		4.9		17.8		10.9		9.6		12.7		21.3		19.6		8.7
Other(2)	3.7		3.7		(1.4	)	7.5		7.3		4.8		15.3		14.3		6.6
Total on-system revenues	$	119.9	$	118.6	1.1		$	259.2	$	240.1	8.0		$	524.8	$	493.1	6.4
Off-system and SPP Integrated Market activity(3)	16.6		4.3		285.8		25.9		8.0		224.4		33.4		16.8		98.5
Total revenues from kWh Sales	136.5		122.9		11.0		285.1		248.1		15.0		558.2		509.9		9.5
Miscellaneous revenues(4)	3.8		3.6		5.3		7.7		6.7		14.5		14.2		10.7		32.6
Total electric operating revenues	$	140.3	$	126.5	10.9		$	292.8	$	254.8	14.9		$	572.4	$	520.6	9.9
Water revenues	0.5		0.5		(2.3	)	1.0		1.0		(1.1	)	2.1		2.0		7.6
Total electric segment operating revenues	$	140.8	$	127.0	10.8		$	293.8	$	255.8	14.9		$	574.5	$	522.6	9.9

(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) As of March 1, 2014, off-system revenues were effectively replaced by SPP Integrated Market activity. SPP integrated market net sales were $16.5 million, $22.8 million and $22.8 million for the three months, six months and twelve months ended, June 30, 2014, periods respectively. See “— Markets and Transmission” below for more information.

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

Revenues for our on-system customers increased $1.3 million during the second quarter of 2014 as compared to the second quarter of 2013. Rate changes, primarily the June 2013 and June 2014 rate increases for our wholesale on-system customers, increased revenues an estimated $2.6 million. An increase in fuel recovery revenue (and corresponding increase in fuel expenses, resulting in no net effect on gross margin) from Missouri customers during the second quarter of 2014 compared to the prior year quarter increased revenues by $0.9 million. Improved customer counts increased revenues an estimated $0.2 million. The impact of other volumetric factors inclusive of weather decreased revenues an estimated $2.4 million.

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Revenues for our on-system customers increased $19.2 million for the six months ended June 30, 2014 as compared to the same period in 2013. Rate changes, primarily the April 2013 Missouri retail on-system customer rate increase and the June 2013 increase for our wholesale on-system customers, contributed an estimated $10.2 million to revenues. Weather and other related factors increased revenues an estimated $6.8 million during the six months ended June 30, 2014. A $1.6 million increase in fuel recovery revenue (and corresponding reduction in fuel expenses, resulting in no net effect on gross margin) from Missouri customers during the six months ended June 30, 2014 compared to the same period in 2013 positively impacted revenues. Improved customer counts increased revenues an estimated $0.6 million.

Revenues for our on-system customers increased $31.6 million for the twelve months ended June 30, 2014 as compared to the same period in 2013. Rate changes, primarily the April 2013 Missouri retail on-system customer rate increase and the June 2013 increase for our wholesale on-system customers, contributed an estimated $26.0 million to revenues. Weather and other related factors increased revenues an estimated $4.0 million during the twelve months ended June 30, 2014. A $3.3 million increase in fuel recovery revenue (and corresponding reduction in fuel expenses, resulting in no net effect on gross margin) from Missouri customers during the twelve months ended June 30, 2014 compared to the same period in 2013 positively impacted revenues. Improved customer counts increased revenues an estimated $1.7 million. A change to our estimate of unbilled revenues in the third quarter of 2012 increased revenues $3.4 million in the 2013 twelve-month period. The 2014 twelve-month ended period does not include a corresponding adjustment.

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, which replaces the real-time EIS market. SPP integrated market 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 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 is recorded as a component of fuel and purchased power on the financial statements. See “— 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.

Miscellaneous Revenues

Our miscellaneous revenues are comprised mainly of transmission revenues, reflecting our position as an SPP transmission owner, late payment fees and renewable energy credit sales.

The following table represents our miscellaneous revenues for our electric segment for the applicable periods ended June 30 (in millions):

	Three Months Ended				Six Months Ended				Twelve Months Ended
	2014		2013		2014		2013		2014		2013

Miscellaneous revenues	$	3.8	$	3.6	$	7.7	$	6.7	$	14.2	$	10.7

Our miscellaneous revenues increased for the three months ended June 30, 2014 period as compared to the same period in 2013, mainly due to increased renewable energy credit sales.

Our miscellaneous revenues increased for the six months ended and the twelve months ended June 30, 2014 periods as compared to the same periods in 2013, mainly due to increased transmission revenues and renewable energy credit sales.

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Operating Revenue Deductions — Fuel and Purchased Power

Included in our fuel and purchased power expenditures are our generation costs and net purchases from the SPP Integrated Marketplace. Net SPP integrated market activity is settled for each market participant in various time increments. As described above, when we purchase more generation from the market than we sell, based on the prescribed time increments, the net purchase is recorded as a component of fuel and purchased power on the financial statements. The table below is a reconciliation of our actual fuel and purchased power expenditures (netted with the regulatory adjustments) to the fuel and purchased power expense shown on our statements of income for the applicable periods ended June 30, 2014 and 2013 (in millions):

	Three Months Ended						Six Months Ended						Twelve Months Ended
	2014			2013			2014			2013			2014			2013
Actual fuel and purchased power expenditures(1)	$	55.8		$	43.7		$	117.0		$	91.5		$	207.6		$	184.5
Missouri fuel adjustment recovery (2)	0.4			(0.4		)	0.7			(0.9		)	(1.1		)	(4.4		)
Missouri fuel adjustment deferral(3)	(0.8		)	(0.7		)	(5.4		)	(1.9		)	(4.1		)	(1.6		)
Kansas and Oklahoma regulatory adjustments(3)	(0.1		)	(0.1		)	(0.6		)	—			(0.9		)	0.1
SWPA amortization(4)	(0.6		)	(0.7		)	(1.4		)	(1.4		)	(2.8		)	(2.9		)
Unrealized (gain)/loss on derivatives	(0.3		)	0.2			(0.4		)	—			(0.7		)	(0.3		)
Total fuel and purchased power expense per income statement	$	54.4		$	42.0		$	109.9		$	87.3		$	198.0		$	175.4

(1) The periods ended June 30, 2014 include SPP integrated market net purchases of $19.6 million, $26.0 million and $26.0 million for the three months, six months and twelve months ended, June 30, 2014 periods, respectively.

(2) A positive amount indicates costs recovered from customers from under recovery in prior deferral periods. A negative amount indicates costs refunded to customers from over recovery in prior deferral periods.

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

(4) Missouri ten year amortization of the $26.6 million payment received from the SWPA in September, 2010, of which $14.1 million of the Missouri portion remains to be amortized as of June 30, 2014.

Operating Revenue Deductions — Other Than Fuel and Purchased Power

The table below shows regulated operating expense increases/(decreases) for the applicable periods ended June 30, 2014 as compared to the same periods in 2013 (in millions):

	Three Months Ended			Six Months Ended			Twelve Months Ended
	2014 vs. 2013			2014 vs. 2013			2014 vs. 2013
Regulated operating expense:
Transmission and distribution expense(1)	$	0.9		$	2.7		$	4.9
General labor expense	0.3			0.9			1.8
Steam power other operating expense	(0.2		)	0.3			0.2
Regulatory commission expense	0.0			0.1			0.5
Customer assistance expense	0.2			0.4			0.6
Customer accounts expense	0.3			0.4			0.8
Employee pension expense	(0.1		)	(0.2		)	0.0
Property insurance	0.2			0.2			0.4
Other power operation expense	0.0			0.1			0.3
Regulatory reversal of gain on prior period sale of assets(2)	0.0			(1.2		)	(1.2		)
Employee health care expense	0.2			(0.8		)	(1.1		)
Injuries and damages expense	(0.3		)	(0.4		)	(0.8		)
Professional services	(0.1		)	(0.1		)	(0.3		)
Banking fees	0.0			(0.1		)	(0.4		)
Other miscellaneous accounts (netted)	(0.1		)	(0.2		)	(0.1		)
TOTAL	$	1.3		$	2.1		$	5.6

(1) Mainly due to increased SPP transmission charges.

(2) Regulatory reversal in 2013 of a prior period gain on the sale of our Asbury unit train as part of our 2013 rate case Agreement with the MPSC.

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The table below shows maintenance and repairs expense increases/(decreases) for the applicable periods ended June 30, 2014 as compared to the same periods in 2013 (in millions):

	Three Months Ended			Six Months Ended			Twelve Months Ended
	2014 vs. 2013			2014 vs. 2013			2014 vs. 2013
Maintenance and repairs expense:
Transmission and distribution	$	0.3		$	2.0		$	3.6
Asbury plant	0.8			0.3			(0.5		)
SLCC	0.3			(0.1		)	(0.8		)
State Line plant	0.0			0.0			0.5
Iatan plant	(0.1		)	0.1			0.3
Plum Point plant	0.0			(0.1		)	0.2
Riverton plant — steam	(0.1		)	(0.2		)	(0.3		)
Riverton plant — gas	0.1			0.3			0.2
Water plant	0.2			0.2			0.2
Other miscellaneous accounts (netted)	0.0			0.1			0.5
TOTAL	$	1.5		$	2.6		$	3.9

Depreciation and amortization expense increased approximately $0.6 million (3.6%), $2.5 million (8.0%) and $7.3 million (12.3%) during the quarter, six month and twelve month periods ended June 30, 2014, respectively, primarily due to increased depreciation rates for the six month and twelve month ended periods resulting from our 2013 Missouri electric rate case settlement and increased plant in service for all periods presented.

Other taxes increased approximately $0.4 million, $1.7 million and $3.9 million during the quarter, six month and twelve month periods ended June 30, 2014, respectively, due to increased property tax reflecting our additions to plant in service and increased municipal franchise taxes.

Gas Segment

Gas Operating Revenues and Sales

The following table details our natural gas sales for the periods ended June 30:

Total Gas Delivered to Customers

	Three Months Ended				Six months ended				Twelve months ended
(bcf sales)	2014	2013	% change		2014	2013	% change		2014	2013	% change
Residential	0.26	0.33	(22.7	)%	1.80	1.67	7.9	%	2.87	2.56	12.1	%
Commercial	0.13	0.18	(27.3	)	0.80	0.79	1.6		1.36	1.26	8.5
Industrial	0.01	0.01	(37.1	)	0.04	0.05	(4.2	)	0.07	0.07	1.8
Other(1)	0.00	0.01	(25.7	)	0.03	0.02	7.6		0.04	0.03	12.3
Total retail sales	0.40	0.53	(24.7	)	2.67	2.53	5.7		4.34	3.92	10.8
Transportation sales	1.05	0.98	7.5		2.61	2.39	9.3		4.75	4.50	5.7
Total gas operating sales	1.45	1.51	(3.8	)	5.28	4.92	7.4		9.09	8.42	8.1

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

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The following table details our natural gas revenues for the periods ended June 30 (dollars in millions):

Operating Revenues and Cost of Gas Sold

	Three Months Ended						Six months ended						Twelve months ended
($ in millions)	2014		2013		% change		2014		2013		% change		2014		2013		% change
Residential	$	4.2	$	4.8	(12.4	)%	$	20.3	$	18.1	12.2	%	$	33.8	$	29.5	14.5	%
Commercial	1.7		2.1		(17.1	)	8.3		7.7		8.5		14.3		12.6		13.5
Industrial	0.1		0.0		65.0		0.4		0.3		31.2		0.6		0.5		26.3
Other(1)	0.0		0.0		(16.2	)	0.3		0.2		14.1		0.4		0.3		17.3
Total retail revenues	$	6.0	$	6.9	(13.3	)	$	29.3	$	26.3	11.3		$	49.1	$	42.9	14.4
Other revenues	0.2		0.2		5.8		0.2		0.2		11.4		0.4		0.4		11.1
Transportation revenues	0.8		0.7		18.5		2.1		1.7		18.7		3.9		3.3		16.1
Total gas operating revenues	$	7.0	$	7.8	(10.1	)	$	31.6	$	28.2	11.8		$	53.4	$	46.6	14.4
Cost of gas sold	2.7		3.1		(14.0	)	17.7		15.0		17.9		28.5		23.3		22.1
Gas operating revenues over cost of gas in rates (margin)	$	4.3	$	4.7	(7.6	)	$	13.9	$	13.2	4.9		$	24.9	$	23.3	6.8

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

Gas retail sales and revenues decreased during the second quarter of 2014 as compared to 2013 reflecting warmer weather during the second quarter of 2014. Heating degree days were 27.8% less in the second quarter of 2014 as compared to the second quarter of 2013 but 3.6% more than the 30-year average. As a result, our gas gross margin (defined as gas operating revenues less cost of gas in rates) decreased $0.4 million in the second quarter of 2014 as compared to the same period in 2013.

Gas retail sales and revenues increased during the six months ended June 30, 2014 as compared to the same period in 2013, reflecting the colder weather in the first quarter of 2014 as compared to the same period in 2013. Our margin for the six months ended June 30, 2014 increased $0.7 million as compared to the same period in 2013.

Gas retail sales and revenues increased during the twelve months ended June 30, 2014 as compared to the same period in 2013, reflecting the colder heating season in 2014. Total heating degree days for the 2013-2014 gas heating season (which runs from November to March) were 19.6% more than the 2012-2013 gas heating season and 15.1% more than the 30-year average gas heating season. Our margin for the twelve months ended June 30, 2014 increased $1.6 million as compared to the same period in 2013.

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 June 30, 2014, we had over recovered purchased gas costs of $0.2 million recorded as a current regulatory liability and $1.7 million recorded as a non-current regulatory liability.

Operating Revenue Deductions

The table below shows regulated operating expense increases/(decreases) for the applicable periods ended June 30, 2014 as compared to the same periods in 2013 (in millions):

	Three Months Ended			Six Months Ended			Twelve Months Ended
	2014 vs. 2013			2014 vs. 2013			2014 vs. 2013
Transmission operation expense	$	0.0		$	0.1		$	0.2
Uncollectible accounts expense	0.0			0.1			0.4
Other miscellaneous accounts (netted)	(0.1		)	(0.2		)	0.0
TOTAL	$	(0.1	)	$	0.0		$	0.6

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

	Three Months Ended						Six Months Ended				Twelve Months Ended
	2014			2013			2014		2013		2014		2013

Gas segment net income	$	(0.3	)	$	(0.2	)	$	2.0	$	1.8	$	2.7	$	2.3

Consolidated Company

Income Taxes

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

	Three Months Ended						Six-Months Ended						Twelve Months Ended
	2014			2013			2014			2013			2014			2013
Consolidated provision for income taxes	$	6.6		$	7.0		$	18.8		$	14.5		$	41.7		$	35.7
Consolidated effective federal and state income tax rates	37.3		%	37.7		%	36.9		%	37.4		%	36.9		%	37.5		%

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

AFUDC increased during all periods presented in 2014 reflecting construction for the environmental retrofit project at our Asbury plant and the Riverton 12 combined cycle. The following table shows the total allowance for funds used during construction (AFUDC) for the applicable periods ended June 30 (in millions):

	Three Months Ended				Six Months Ended				Twelve Months Ended
($ in millions)	2014		2013		2014		2013		2014		2013
Allowance for equity funds used during construction	$	1.5	$	0.8	$	2.8	$	1.4	$	5.2	$	2.4
Allowance for borrowed funds used during construction	0.8		0.5		1.6		0.8		2.9		1.4
Total AFUDC	$	2.3	$	1.3	$	4.4	$	2.2	$	8.1	$	3.8

The change in long-term debt interest for 2014 compared to 2013 reflects the issuance, on May 30, 2013, of $30.0 million of 3.73% First Mortgage Bonds due May 30, 2033 and $120.0 million of 4.32% First Mortgage Bonds due May 30, 2043. We used a portion of the proceeds from the sale of these bonds to redeem all $98.0 million aggregate principal amount of our Senior Notes, 4.50% Series due June 15, 2013. Total interest charges on long-term and short-term debt for the periods ended June 30 are shown below (dollars in millions):

Interest Charges

	Second	Second			6 Months	6 Months			12 Months	12 Months
	Quarter	Quarter	%		Ended	Ended	%		Ended	Ended	%
	2014	2013	Change		2014	2013	Change		2014	2013	Change
Long-term debt interest	10.1	10.2	(0.8	)%	20.2	20.2	0.3	%	40.4	40.0	1.0	%
Short-term debt interest	0.0	0.0	10.0		0.0	0.1	(69.8	)	0.0	0.1	(78.7	)
Other interest	0.3	0.3	(4.3	)	0.5	0.5	(9.1	)	1.0	1.1	(7.1	)
Total interest charges	10.4	10.5	(0.9	)	20.7	20.8	(0.1	)	41.4	41.2	0.6

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RATE MATTERS

We 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, 2011:

Jurisdiction	Date Requested	Annual Increase Granted		Percent Increase Granted		Date Effective
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
Missouri — Electric	September 28, 2010	$	18,700,000	4.70	%	June 15, 2011
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
Oklahoma — Electric	January 28, 2011	$	1,063,100	9.32	%	March 1, 2011
Arkansas - Electric	August 19, 2010	$	2,104,321	19.00	%	April 13, 2011

On May 28, 2014, we filed a Notice of Intended Case Filing with the Missouri Public Service Commission (MPSC) of our intentions to file an electric rate case in Missouri as early as August 1, 2014.

On May 18, 2012, we filed a request with the Federal Energy Regulatory Commission (FERC) to implement a cost-based transmission formula rate (TFR). On June 13, 2013, we, the Kansas Corporation Commission and the cities of Monett, Mt. Vernon and Lockwood, Missouri and Chetopa, Kansas, filed a unanimous Settlement Agreement (Agreement) with the FERC. The Agreement includes a TFR that establishes an ROE of 10.0%. The FERC conditionally approved the Agreement on November 18, 2013, and we made a compliance filing with the FERC on December 18, 2013 in connection with this conditional approval. The FERC approved our compliance filing on June 12, 2014.

Our other rate cases, as we reported in our Annual Report on Form 10-K for the year ended December 31, 2013, remain unchanged. See Note 3, “Regulatory Matters” in our Annual Report on Form 10-K for the year ended December 31, 2013 for additional information.

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MARKETS AND TRANSMISSION

Electric Segment

Day Ahead Market: On March 1, 2014, the SPP RTO implemented its Integrated Marketplace (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. The SPP BA is providing operational, economic and NERC Compliance benefits to our customers.

As part of the Integrated Marketplace, we and other SPP members are able to submit generation offers to sell power and bids to purchase power into the SPP market, the SPP serving as a centralized dispatch of SPP members’ generation resources. The SPP matches offers and bids based upon operating and reliability considerations. It is expected that 90%-95% of all next day generation needed throughout the SPP territory will be cleared through this Integrated Marketplace. We also acquire Transmission Congestion Rights (TCR) in an attempt to mitigate congestion costs associated with the power we will purchase from the SPP Integrated Market. The net financial effect of these Integrated Marketplace transactions are included in our fuel adjustment mechanisms.

Plum Point Transmission Delivery Costs: On December 19, 2013, Entergy 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 significantly increase transmission delivery costs for our Plum Point power station as well as utilize our transmission system without compensation. In February 2014, the FERC granted a Request For Rehearing regarding the increased MISO transmission rate for Plum Point and established its own docket that was consolidated with the Entergy transmission formula rate docket. The consolidated dockets were set for settlement evidentiary hearings. Settlement discussions are ongoing.

SPP/Midcontinent Independent System Operator (MISO) Joint Operating Agreement: Prior to Entergy’s integration into MISO, the SPP filed a Petition for Review of FERC’s Orders on the interpretation of the SPP/MISO Joint Operating Agreement at the United States Court of Appeals for the District of Columbia (DC). In early December 2013, the DC Court vacated and remanded FERC’s Orders that agreed with MISO regarding interpretation of the Joint Operating Agreement to utilize SPP’s system to integrate Entergy into MISO. The SPP’s position is that MISO’s intentional and free use of the SPP transmission system was unjust and unreasonable and made unexecuted service agreement filings at the FERC in February 2014 to initiate billings to MISO. SPP members have intervened in the SPP’s Petition and are actively involved in the SPP stakeholder processes and other FERC dockets to address our concerns. In March 2014, the FERC issued key Orders accepting the SPP’s filing to collect transmission revenues on our behalf, subject to refund, and established a settlement hearing process for resolution of the SPP/MISO dispute. Although the FERC’s order is positive, the transmission revenue financial impact and realization of such increased revenues due to MISO’s use of the SPP transmission system, including our system, is uncertain at this time and may take several months for a FERC acceptance of a resolution between the parties.

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, 2013.

LIQUIDITY AND CAPITAL RESOURCES

Overview. Our primary sources of liquidity are cash provided by operating activities, short-term borrowings under our commercial paper program (which is supported by our credit facilities) and borrowings from our unsecured revolving credit facility. We raise 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

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service commissions and the SEC. We believe the cash provided by operating activities, together 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, 2013 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 six months ended June 30 (in millions):

Summary of Cash Flows

	2014			2013			Change
Cash provided by/(used in):
Operating activities	$	69.0		$	71.0		$	(2.0	)
Investing activities	(100.4		)	(73.2		)	(27.2		)
Financing activities	30.9			9.7			21.2
Net change in cash and cash equivalents	$	(0.5	)	$	7.5		$	(8.0	)

Cash flow from Operating Activities

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

Period-over-period changes in our operating cash flows are attributable primarily to working capital changes resulting from the impact of weather, the timing of customer collections, payments for natural gas and coal purchases, 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.

Six Months Ended June 30, 2014 Compared to 2013. During the six months ended June 30, 2014, our net cash flows provided from operating activities decreased $2.0 million or 2.8% from 2013. This change resulted primarily from the following:

· Increase in net income - $7.8 million.

· Increased plant in service depreciation - $2.2 million and fuel adjustment amortizations - $1.8 million.

· Increased cash flow from changes in property tax accruals - $2.6 million.

· Increased cash flow from fuel adjustment deferrals - $1.4 million.

· Changes related to other post-employment benefits - $1.0 million.

· Adjustment to cash flow for increased AFUDC - $(1.4) million.

· Cash flow adjustments related to the 2013 Missouri electric rate case for a loss on plant disallowance - $(2.4) million and a reversal of a prior period gain on the sale of assets - $(1.2) million.

· Lower cash flow adjustments for deferred taxes mostly based on the expiration of bonus depreciation - $(8.6) million.

· Cash outflows resulting from settlements of asset retirement obligations - $(1.2) million.

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Capital Requirements and Investing Activities

Our net cash flows used in investing activities increased $27.2 million during the six months ended June 30, 2014 as compared to the same period in 2013.

Our capital expenditures incurred totaled approximately $96.9 million during the six months ended June 30, 2014 compared to $76.2 million for the six months ended June 30, 2013. The increase was primarily the result of an increase in new generation construction due to the Riverton 12 combined cycle construction.

A breakdown of the capital expenditures for the six months ended June 30, 2014 and 2013 is as follows (in millions):

	Capital Expenditures
	2014			2013
Distribution and transmission system additions	$	32.4		$	27.0
New Generation — Riverton 12 combined cycle	29.6			1.1
Additions and replacements — electric plant	23.0			40.2
Storms	1.9			0.2
Transportation	0.4			0.4
Gas segment additions and replacements	4.4			2.1
Other (including retirements and salvage -net) (1)	4.4			4.3
Subtotal	96.1			75.3
Non-regulated capital expenditures (primarily fiber optics)	0.8			0.9
Subtotal capital expenditures incurred (2)	96.9			76.2
Adjusted for capital expenditures payable (3)	(1.3		)	(0.4		)
Total cash outlay	$	95.6		$	75.8

(1) Other includes equity AFUDC of $(2.8) million and $(1.4) million for 2014 and 2013, respectively.

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

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

Approximately 7.0% of our cash requirements for capital expenditures during the second quarter of 2014 were satisfied from internally generated funds (funds provided by operating activities less dividends paid).

We estimate that internally generated funds (funds provided by operating activities less dividends paid) will provide approximately 45.8% of the funds required for the remainder of our budgeted 2014 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. In addition, we plan to issue private placement debt with a delayed settlement option in the near term. We expect this financing to be in the range of $60 million. If additional financing is needed, we intend to utilize a combination of debt and equity securities. For further information see Note 6 of “Notes to Consolidated Financial Statements (Unaudited).”

Financing Activities

Our net cash flows provided by financing activities was $30.9 million in the six months ended June 30, 2014, an increase of $21.2 million as compared to the six months ended June 30, 2013, primarily due to the following:

· Issuance of $48.5 million in short-term debt in the six months ended June 30, 2014 as compared to repayment of $24.0 million in short-term debt in the six months ended June 30, 2013.

· No first mortgage bonds issued in the six months ended June 30, 2014 compared to $150.0 million issued in the six months ended June 30, 2013.

· No repayment of senior notes in the six months ended June 30, 2014 compared to $98.0 million of senior notes repaid in the six months ended June 30, 2013.

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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. We have received regulatory approval for the issuance of securities under this shelf from all four state jurisdictions in our electric service territory, but we may only issue up to $150 million of such securities in the form of first mortgage bonds. We plan to use proceeds from 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 January 17, 2012, we entered into the Third Amended and Restated Unsecured Credit Agreement which amended and restated our Second Amended and Restated Unsecured Credit Agreement dated January 26, 2010. This agreement extended the termination date of the revolving credit facility from January 26, 2013 to January 17, 2017. The agreement also removed the letter of credit facility and includes a swingline loan facility with a $15 million swingline loan sublimit. The aggregate amount of the revolving credit commitments remains $150 million, inclusive of the $15 million swingline loan sublimit. In addition, the pricing and fees under the facility were amended. Interest on borrowings under the facility accrues at a rate equal to, at our option, (i) the highest of (A) the bank’s prime commercial rate, (B) the federal funds effective rate plus 0.5% or (C) one month LIBOR plus 1.0%, plus a margin or (ii) one month, two month or three month LIBOR, in each case, plus a margin. Each margin is based on our current credit ratings and the pricing schedule in the facility. As of the date hereof, and based on our current credit ratings, the LIBOR margin under the facility is 1.25%. A facility fee is payable quarterly on the full amount of the commitments under the facility based on our current credit ratings, which fee is currently 0.20%. In addition, upon entering into the amended and restated facility, we paid an upfront fee to the revolving credit banks of $262,500 in the aggregate. There were no other material changes to the terms of the facility.

The facility is used for working capital, general corporate purposes and to back-up our use of commercial paper. This facility requires our total indebtedness to be less than 62.5% of our total capitalization at the end of each fiscal quarter and our EBITDA (defined as net income plus interest, taxes, depreciation and amortization) to be at least two times our interest charges for the trailing four fiscal quarters at the end of each fiscal quarter. Failure to maintain these ratios will result in an event of default under the credit facility and will prohibit us from borrowing funds thereunder. As of June 30, 2014, we are in compliance with these ratios. Our total indebtedness is 51.0% of our total capitalization as of June 30, 2014 and our EBITDA is 5.9 times our interest charges. This credit facility is also subject to cross-default if we default on in excess of $10 million in the aggregate on our other indebtedness. This arrangement does not serve to legally restrict the use of our cash in the normal course of operations. There were no outstanding borrowings under this agreement at June 30, 2014. However, $52.5 million was used to back up our outstanding commercial paper.

EDE Mortgage Indenture

The principal amount of all series of first mortgage bonds outstanding at any one time under the EDE Mortgage is limited by terms of the mortgage to $1.0 billion. Substantially all of the property, plant and equipment of The Empire District Electric Company (but not its subsidiaries) is subject to the lien of the EDE Mortgage. Restrictions in the EDE mortgage bond indenture could affect our liquidity. The EDE Mortgage contains a requirement that for new first mortgage bonds to be issued, our net earnings (as defined in the EDE Mortgage) for any twelve consecutive months within the fifteen months preceding issuance must be two times the annual interest requirements (as defined in the EDE Mortgage) on all first mortgage bonds then outstanding and on the prospective issue of new first mortgage bonds. Our earnings for the twelve months ended June 30, 2014 would permit us to issue approximately $719.7 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

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additions. At June 30, 2014, we had retired bonds and net property additions which would enable the issuance of at least $899.3 million principal amount of bonds if the annual interest requirements are met. However, based on the $1 billion limit on the principal amount of first mortgage bonds outstanding set forth by the EDE mortgage, and our current level of outstanding first mortgage bonds, we are limited to the issuance of $417.0 million of new first mortgage bonds. As of June 30, 2014, 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 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 June 30, 2014, this test would allow us to issue approximately $18.8 million principal amount of new first mortgage bonds at an assumed interest rate of 5.5%.

Credit Ratings

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

	Fitch	Moody’s	Standard & Poor’s
Corporate Credit Rating	n/r*	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 January 30, 2014, Moody’s upgraded our corporate credit rating to Baa1 from Baa2, senior secured debt to A2 from A3, senior unsecured debt to Baa1 from Baa2 and affirmed our commercial paper rating at P-2. Standard & Poor’s and Fitch reaffirmed our ratings on March 20, 2014 and June 11, 2014, respectively.

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 June 30, 2014, compared to December 31, 2013. See “Contractual Obligations” in our Annual Report on Form 10-K for the year ended December 31, 2013.

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.

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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 AND ESTIMATES

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, 2013 for a discussion of additional critical accounting policies and estimates. There were no changes in these policies or estimates in the quarter ended June 30, 2014.

RECENTLY ISSUED ACCOUNTING STANDARDS

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

Item 3. Quantitative and Qualitative Disclosures about Market Risk

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

Market Risk and Hedging Activities.

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

We engage in physical and financial trading activities with the goals of reducing risk from market fluctuations. In accordance with our established Energy Risk Management Policy, which typically includes entering into various derivative transactions, we attempt to mitigate our commodity market risk. Derivatives are utilized to manage our gas commodity market risk. We also acquire Transmission Congestion Rights (TCR) in an attempt to lessen the cost of power we purchase from the SPP Integrated Market due to congestion costs. See Note 4 of “Notes to Consolidated Financial Statements (Unaudited)” for further information.

Commodity Price Risk.

We are exposed to the impact of market fluctuations in the price and transportation costs of coal, natural gas, and electricity and employ established policies and procedures to manage the risks associated with these market fluctuations, including utilizing derivatives.

We satisfied 65.8% of our 2013 generation fuel supply need through coal. Approximately 96% of our 2013 coal supply was Western coal. We have contracts and binding proposals to supply a portion of the fuel for our coal plants through 2016. These contracts satisfy approximately 95% of our anticipated fuel requirements for 2014, 58% for 2015, 39% for 2016 and 19% 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 June 30, 2014, 66%, or

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4.2 million Dths’s, of our anticipated volume of natural gas usage for our electric operations for the remainder of 2014 is hedged.

Based on our expected natural gas purchases for our electric operations for the next twelve months, if average natural gas prices should increase 10% more than the price at June 30, 2014, our natural gas expenditures would increase by approximately $1.8 million based on our June 30, 2014 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 June 30, 2014, we have 0.8 million Dths in storage on the three pipelines that serve our customers. This represents 39% of our storage capacity. We have an additional 0.1 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 result of exceeding agreed-upon credit exposure thresholds or may be required to prepay the transaction. Conversely, we are required to post collateral with counterparties at certain thresholds, which is typically the result of changes in commodity prices. Amounts reported as margin deposit liabilities represent counterparty funds we hold that result from various trading counterparties exceeding agreed-upon credit exposure thresholds. Amounts reported as margin deposit assets represent our funds held on deposit for our NYMEX contracts with our broker and other financial contracts with other counterparties that resulted from us exceeding agreed-upon credit limits established by the counterparties. The following table depicts our margin deposit assets at June 30, 2014 and December 31, 2013(in millions).

	June 30, 2014		December 31, 2013

Margin deposit assets	$	3.5	$	5.2

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 small group of counterparties and transactions may involve large notional volumes and potentially volatile commodity prices. Below is a table showing our net credit exposure at June 30, 2014, 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	$	0.1
Net unrealized mark-to-market losses for financial natural gas contracts	2.8
Net credit exposure	$	2.9

The $2.8 million net unrealized mark-to-market loss for financial natural gas contracts is comprised entirely of $2.8 million for which our counterparties are exposed to Empire for unrealized losses. We are holding no collateral from any counterparty since they are below the $10.0 million mark-to-market collateral threshold in our agreements. As noted above, as of June 30, 2014, we have $3.5 million on deposit for NYMEX contract exposure to Empire, of which $3.3 million represents our collateral requirement. If NYMEX gas prices decreased 25% from their June 30, 2014 levels, our collateral requirement would increase $11.3 million. If these prices increased 25%, our collateral

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requirement would decrease $1.6 million. Our other counterparties would not be required to post collateral with Empire.

We sell electricity and gas and provide distribution and transmission services to a diverse group of customers, including residential, commercial and industrial customers. Credit risk associated with trade accounts receivable from energy customers is limited due to the large number of customers. In addition, we enter into contracts with various companies in the energy industry for purchases of energy-related commodities, including natural gas in our fuel procurement process.

Interest Rate Risk.

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

If market interest rates average 1% more in 2014 than in 2013, our interest expense would increase, and income before taxes would decrease by less than $0.3 million. This amount has been determined by considering the impact of the hypothetical interest rates on our highest month-end commercial paper balance for 2013. These analyses do not consider the effects of the reduced level of overall economic activity that could exist in such an environment. In the event of a significant change in interest rates, management would likely take actions to further mitigate its exposure to the change. However, due to the uncertainty of the specific actions that would be taken and their possible effects, the sensitivity analysis assumes no changes in our financial structure.

Item 4. Controls and Procedures

As of the end of the period covered by this report, an evaluation was carried out, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as such term is defined in Rule 13a-15(e) of the Securities Exchange Act of 1934). Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of June 30, 2014.

There have been no changes in our internal control over financial reporting that occurred during the second quarter of 2014 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, 2013.

Item 5. Other Information.

For the twelve months ended June 30, 2014, our ratio of earnings to fixed charges was 3.17x. See Exhibit (12) hereto.

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Item 6. Exhibits.

(a) Exhibits.

(10)(a) Amended and Restated Employee Stock Purchase Plan (incorporated by reference to Appendix A to the definitive proxy statement filed pursuant to Regulation 14A on March 19, 2014, File No. 1-03368).

(10)(b) 2015 Stock Incentive Plan (incorporated by reference to Appendix B to the definitive proxy statement filed pursuant to Regulation 14A on March 19, 2014, File No. 1-03368).

(10)(c) Amended and Restated Stock Unit Plan for Directors (incorporated by reference to Appendix C to the definitive proxy statement filed pursuant to Regulation 14A on March 19, 2014, File No. 1-03368).

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

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

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

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

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

(101) The following financial information from The Empire District Electric Company’s Quarterly Report on Form 10-Q for the period ended June 30, 2014, filed with the SEC on August 8, 2013, formatted in Extensible Business Reporting Language (XBRL): (i) the Consolidated Statements of Income for the three, six and twelve month periods ended June 30, 2014 and 2013, (ii) the Consolidated Balance Sheets at June 30, 2014 and December 31, 2013, (iii) the Consolidated Statements of Cash Flows for the six-month periods ended June 30, 2014 and 2013, and (iv) Notes to Consolidated Financial Statements.**

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

**Pursuant to Rule 406T of Regulation S-T, the XBRL related information in Exhibit 101 to this Quarterly Report on Form 10-Q shall not be deemed to be “filed” for purposes of Section 18 of the Exchange Act, or otherwise subject to the liability of that section, and shall not be deemed incorporated by reference into, or part of a registration statement, prospectus or other document filed under the Securities Act of 1933, as amended or the Exchange Act of 1934, as amended except as shall be expressly set forth by specific reference in such filings.

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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

August 8, 2014

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