10-Q

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended March 31, 2016 or

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

For the transition period from                to             .

Commission file number: 1-3368

THE EMPIRE DISTRICT ELECTRIC COMPANY

(Exact name of registrant as specified in its charter)

Kansas
(State of Incorporation) 44-0236370
(I.R.S. Employer Identification No.)

602 S. Joplin Avenue, Joplin, Missouri
(Address of principal executive offices) 64801
(zip code)

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

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes x  No o

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

Large accelerated filer x	Accelerated filer o
Non-accelerated filer  o  (Do not check if a smaller reporting company)	Smaller reporting company o

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

As of April 29, 2016, 43,923,742 shares of common stock were outstanding.

THE EMPIRE DISTRICT ELECTRIC COMPANY

INDEX

		PAGE
	Forward Looking Statements	3
Part I -	Financial Information:
Item 1.	Financial Statements:
	a. Consolidated Statements of Income	5
	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	27
	Executive Summary	27
	Results of Operations	30
	Rate Matters	36
	Markets and Transmission	36
	Liquidity and Capital Resources	37
	Contractual Obligations	41
	Dividends	41
	Off-Balance Sheet Arrangements	41
	Critical Accounting Policies and Estimates	41
	Recently Issued Accounting Standards	41
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	41
Item 4.	Controls and Procedures	43
Part II -	Other Information:	44
Item 1.	Legal Proceedings	44
Item 1A.	Risk Factors	44
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	44
Item 6.	Exhibits	44
	Signatures	46

2

FORWARD LOOKING STATEMENTS

Certain matters discussed in this quarterly report are “forward-looking statements” intended to qualify for the safe harbor from liability established by the Private Securities Litigation Reform Act of 1995. Such statements address or may address future plans, objectives, expectations and events or conditions concerning various matters such as the pending acquisition of Empire by Liberty Utilities (Central) Co. (Liberty Central), a subsidiary of Algonquin Power & Utilities Corp. (APUC) (the Merger), 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 impact of energy efficiency and alternative energy sources, including solar;

·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;

·electric utility restructuring, including deregulation;

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

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

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

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

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

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

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

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

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

·changes in accounting requirements;

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

·performance of acquired businesses;

·other circumstances affecting anticipated rates, revenues and costs; and

·certain risks and uncertainties associated with the Merger, including, without limitation:

·the risk that Empire may be unable to obtain shareholder approval for the proposed transaction or that Liberty Central or Empire may be unable to obtain governmental and regulatory approvals required for the proposed transaction, or required governmental and regulatory approvals may delay the proposed transaction;

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·the risk that any other condition to the closing of the proposed transaction may not be satisfied;

·the occurrence of any event, change or other circumstances that could give rise to the termination of the merger agreement or could otherwise cause the failure of the Merger to close;

·the failure of Liberty Central or APUC to obtain any financing necessary to complete the merger;

·the outcome of any legal proceedings, regulatory proceedings or enforcement matters that have been or may be instituted against Empire and others relating to the merger agreement;

·the receipt of an unsolicited offer from another party to acquire assets or capital stock of Empire that could interfere with the proposed Merger;

·the timing to consummate the proposed transaction;

·disruption from the proposed transaction making it more difficult to maintain relationships with customers, employees, regulators or suppliers;

·the diversion of management time and attention on the transaction;

·the amount of  costs, fees, expenses, and charges related to the Merger; and

·the effect and timing of changes in laws or in governmental regulations (including environmental laws and regulations) that could adversely affect our participation in the Merger.

All such factors are difficult to predict, contain uncertainties that may materially affect actual results, and may be beyond our control. Additional risks and uncertainties have been or will be discussed in the proxy statement and other materials that Empire has filed or will file with the SEC in connection with the Merger. New factors emerge from time to time and it is not possible for management to predict all factors or to assess the impact of each such factor on us. Any forward-looking statement speaks only as of the date on which such statement is made, and we do not undertake any obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement is made.

We caution you that any forward-looking statements are not guarantees of future performance and involve known and unknown risk, uncertainties and other factors which may cause our actual results, performance or achievements to differ materially from the facts, results, performance or achievements we have anticipated in such forward-looking statements.

4

PART I.  FINANCIAL INFORMATION

Item 1. Financial Statements

THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

	Three Months Ended
	March 31,
	2016			2015
	(000’s except per share amounts)
Operating revenues:
Electric	$	134,363		$	142,641
Gas	15,113			19,818
Other	1,839			2,085
	151,315			164,544
Operating revenue deductions:
Fuel and purchased power	37,840			48,977
Cost of natural gas sold and transported	7,561			11,423
Regulated operating expenses	27,845			28,551
Other operating expenses	961			805
Maintenance and repairs	10,218			10,267
Merger related expenses	4,248			—
Depreciation and amortization	20,403			20,020
Provision for income taxes	8,675			8,884
Other taxes	10,321			10,904
	128,072			139,831
Operating income	23,243			24,713
Other income and (deductions):
Allowance for equity funds used during construction	1,704			978
Interest income	9			11
Benefit for other income taxes	36			113
Other - non-operating expense, net	(408		)	(698		)
	1,341			404
Interest charges:
Long-term debt	11,298			10,751
Short-term debt	62			73
Allowance for borrowed funds used during construction	(1,053		)	(564		)
Other	268			220
	10,575			10,480
Net income	$	14,009		$	14,637
Weighted average number of common shares outstanding - basic	43,882			43,531
Weighted average number of common shares outstanding — diluted	43,937			43,612
Total earnings per weighted average share of common stock — basic and diluted	$	0.32		$	0.34
Dividends declared per share of common stock	$	0.26		$	0.26

See accompanying Notes to Consolidated Financial Statements.

5

THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

	Twelve Months Ended
	March 31,
	2016			2015
	(000’s except per share amounts) amounts)
Operating revenues:
Electric	$	546,808		$	582,043
Gas	36,997			47,051
Other	8,539			8,107
	592,344			637,201
Operating revenue deductions:
Fuel and purchased power	158,723			208,477
Cost of natural gas sold and transported	15,639			23,403
Regulated operating expenses	112,845			111,371
Other operating expenses	3,466			3,076
Maintenance and repairs	48,474			46,784
Merger related expenses	4,499			—
Depreciation and amortization	80,933			75,264
Provision for income taxes	34,592			36,108
Other taxes	38,595			37,493
	497,766			541,976
Operating income	94,578			95,225
Other income and (deductions):
Allowance for equity funds used during construction	5,577			6,147
Interest income	144			20
Benefit for other income taxes	910			237
Other - non-operating expense, net	(2,887		)	(1,655		)
	3,744			4,749
Interest charges:
Long-term debt	44,348			41,283
Short-term debt	255			181
Allowance for borrowed funds used during construction	(3,333		)	(3,320		)
Other	1,083			995
	42,353			39,139
Net income	$	55,969		$	60,835
Weighted average number of common shares outstanding - basic	43,758			43,395
Weighted average number of common shares outstanding — diluted	43,777			43,460
Total earnings per weighted average share of common stock — basic and diluted	$	1.28		$	1.40
Dividends declared per share of common stock	$	1.04		$	1.03

See accompanying Notes to Consolidated Financial Statements.

6

THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS (UNAUDITED)

	March 31, 2016		December 31, 2015
	($-000’s)
Assets
Plant and property, at original cost:
Electric	$	2,492,315	$	2,473,927
Gas	84,586		83,402
Other	44,739		44,263
Construction work in progress	194,568		183,689
	2,816,208		2,785,281
Accumulated depreciation and amortization	779,891		764,895
	2,036,317		2,020,386
Current assets:
Cash and cash equivalents	1,672		1,753
Restricted cash	4,727		4,726
Accounts receivable — trade, net of allowance of $820 and $623 respectively	43,357		40,162
Accrued unbilled revenues	15,661		20,653
Accounts receivable — other	22,283		28,320
Fuel, materials and supplies	58,349		60,950
Prepaid expenses and other	8,070		8,835
Unrealized gain in fair value of derivative contracts	608		1,295
Regulatory assets	7,145		7,052
	161,872		173,746
Noncurrent assets and deferred charges:
Regulatory assets	209,934		209,708
Goodwill	39,492		39,492
Unrealized gain in fair value of derivative contracts	—		16
Other	3,311		3,297
	252,737		252,513
Total Assets	$	2,450,926	$	2,446,645

(Continued)

See accompanying Notes to Consolidated Financial Statements.

7

THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS (UNAUDITED) (Continued)

	March 31, 2016		December 31, 2015
	($-000’s)
Capitalization and Liabilities
Common stock, $1 par value, 43,911,310 and 43,820,726 shares issued and outstanding, respectively	$	43,911	$	43,821
Capital in excess of par value	660,364		657,466
Retained earnings	104,039		101,443
Total common stockholders’ equity	808,314		802,730
Long-term debt (net of current portion):
Obligations under capital lease	3,500		3,580
First mortgage bonds and secured debt	724,996		724,838
Unsecured debt	100,949		100,935
Total long-term debt	829,445		829,353
Total long-term debt and common stockholders’ equity	1,637,759		1,632,083
Current liabilities:
Accounts payable and accrued liabilities	43,477		66,946
Current maturities of long-term debt	25,267		25,246
Short-term debt	19,000		25,000
Regulatory liabilities	10,154		8,615
Customer deposits	14,793		14,623
Interest accrued	14,933		7,348
Unrealized loss in fair value of derivative contracts	4,743		4,472
Taxes accrued	9,076		2,832
Other current liabilities	297		323
	141,740		155,405
Commitments and contingencies (Note 7)
Noncurrent liabilities and deferred credits:
Regulatory liabilities	134,401		132,457
Deferred income taxes	405,250		396,542
Unamortized investment tax credits	18,452		18,487
Pension and other postretirement benefit obligations	83,394		82,144
Unrealized loss in fair value of derivative contracts	3,873		3,696
Other	26,057		25,831
	671,427		659,157
Total Capitalization and Liabilities	$	2,450,926	$	2,446,645

See accompanying Notes to Consolidated Financial Statements.

8

THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

	Three Months Ended
	March 31,
	2016			2015
	($-000’s)
Operating activities:
Net income	$	14,009		$	14,637
Adjustments to reconcile net income to cash flows from operating activities:
Depreciation and amortization including regulatory items	19,967			23,056
Pension and other postretirement benefit costs, net of contributions	3,164			1,704
Deferred income taxes and unamortized investment tax credit, net	8,640			7,203
Allowance for equity funds used during construction	(1,704		)	(978		)
Stock compensation expense	2,107			651
Non-cash (gain)/loss on derivatives	909			772
Other	103			—
Cash flows impacted by changes in:
Accounts receivable and accrued unbilled revenues	6,843			12,475
Fuel, materials and supplies	2,601			1,632
Prepaid expenses, other current assets and deferred charges	(2,241		)	2,984
Accounts payable and accrued liabilities	(22,969		)	(28,343		)
Interest, taxes accrued and customer deposits	13,999			15,159
Asset retirement obligations	(40		)	—
Other liabilities and other deferred credits	5,987			3,800
Net cash provided by operating activities	51,375			54,752
Investing activities:
Capital expenditures — regulated	(35,359		)	(52,954		)
Capital expenditures and other investments — non-regulated	(417		)	(520		)
Restricted cash	1			—
Net cash used in investing activities	(35,775		)	(53,474		)
Financing activities:
Proceeds from issuance of common stock, net of issuance costs	1,809			1,664
Net short-term borrowings	(6,000		)	9,000
Dividends	(11,413		)	(11,318		)
Other	(77		)	(68		)
Net cash used in financing activities	(15,681		)	(722		)
Net increase/(decrease) in cash and cash equivalents	(81		)	556
Cash and cash equivalents at beginning of period	1,753			2,105
Cash and cash equivalents at end of period	$	1,672		$	2,661

See accompanying Notes to Consolidated Financial Statements.

9

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

Note 1 - Summary of Significant Accounting Policies

We operate our businesses as three segments:  electric, gas and other. The Empire District Electric Company (EDE), a Kansas corporation organized in 1909, is an operating public utility engaged in the generation, purchase, transmission, distribution and sale of electricity in parts of Missouri, Kansas, Oklahoma and Arkansas. As part of our electric segment, we also provide water service to three towns in Missouri. The Empire District Gas Company (EDG) is our wholly-owned subsidiary which provides natural gas distribution to 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, 2015.

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, 2015.

On February 9, 2016, Empire entered into an Agreement and Plan of Merger (the Merger Agreement) with Liberty Utilities (Central) Co., a Delaware corporation (Liberty Central), and Liberty Sub Corp., a Kansas corporation (Merger Sub), providing for the merger of Merger Sub with and into Empire, with Empire surviving the Merger as a wholly-owned subsidiary of Liberty Central (the Merger). See Note 13 for further information.

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. In July 2015, the FASB approved a one year delay in the standard’s effective date. The new standard is now effective for interim and annual reporting periods beginning after December 15, 2017. We are evaluating the impact of the adoption of this standard.

Presentation of debt issuance costs:  In April 2015, the FASB issued revised guidance addressing the presentation requirements for debt issuance costs. Under the revised guidance, all costs incurred to issue debt are to be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability. The revised guidance is effective for interim and annual reporting periods beginning after December 15, 2015. The application of this standard resulted in $8.5 million in unamortized debt issuance costs being reclassified from deferred charges to long-term debt on the March 31, 2016 Consolidated Balance Sheet and $8.7 million in unamortized debt issuance costs being reclassified from deferred charges to long-term debt on the December 31, 2015 Consolidated Balance Sheet for comparative purposes.

Recognition and measurement of financial assets and financial liabilities:  In January 2016, the FASB issued revised guidance addressing the recognition, measurement, presentation and disclosure of financial instruments.  Under the revised guidance all equity investments (except those accounted for under the equity method of accounting or those that result in consolidation of the investee) are to be measured at fair value with the changes in fair value recognized in net income.  The amended guidance also addresses the impairment assessment of some equity investments, as well as disclosure requirements. The revised guidance is effective for interim and annual periods beginning after December 15, 2017.  The application of this standard is not expected to have a material impact on our results of operations, financial position or liquidity.

Leases:  In February 2016, the FASB issued new guidance on accounting for leases.  Under the new guidance a lessee will be required to recognize the assets and liabilities arising from leases on the balance sheet.  The new guidance also addresses the income statement treatment for leases. 

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Under the new guidance leases will be classified as either operating or financing based on criteria that are similar to the old guidance.  Lease expense will be recognized on a straight line basis for operating leases while expense for capital leases will be similar to the finance pattern utilized today.  The new guidance is effective for interim and annual periods beginning after December 15, 2018, with early adoption permitted.  We are evaluating the impact of the adoption of this standard.

Stock Compensation:  In March 2016 the FASB issued revised guidance on stock compensation.  The updated guidance is intended to simplify some aspects of the accounting for stock compensation such as the income tax impact, classification of awards as either equity or liabilities, and cash flow classification. This guidance will be effective for 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, 2015 for further information regarding recently issued and proposed accounting standards.

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Note 3— Regulatory Matters

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

Regulatory Assets and Liabilities

	March 31, 2016			December 31, 2015
Regulatory Assets:
Current:
Under recovered fuel costs	$	89		$	196
Current portion of long-term regulatory assets	7,056			6,856
Regulatory assets, current	7,145			7,052
Long-term:
Pension and other postretirement benefits(1)	106,237			108,273
Income taxes	48,597			48,613
Deferred construction accounting costs(2)	14,886			14,977
Unamortized loss on reacquired debt	9,563			9,731
Unsettled derivative losses — electric segment	7,785			7,775
System reliability — vegetation management	3,346			3,604
Storm costs	3,389			3,531
Asset retirement obligation	8,644			7,722
Customer programs	6,112			5,942
Missouri solar initiative(3)	6,170			3,504
Current portion of long-term regulatory assets	(7,056		)	(6,856		)
Other	2,261			2,892
Regulatory assets, long-term	209,934			209,708
Total Regulatory Assets	$	217,079		$	216,760

	March 31, 2016			December 31, 2015
Regulatory Liabilities:
Current:
Over recovered fuel costs	$	6,789		$	5,280
Current portion of long-term regulatory liabilities	3,365			3,335
Regulatory liabilities, current	10,154			8,615
Long-term:
Costs of removal(4)	95,673			94,193
SWPA payment for Ozark Beach lost generation	13,580			14,213
Income taxes	11,194			11,244
Deferred construction accounting costs — fuel(5)	7,651			7,690
Unamortized gain on interest rate derivative	2,989			3,031
Pension and other postretirement benefits	1,698			1,745
Over recovered fuel costs	3,168			2,300
System reliability — vegetation management	1,320			1,320
Current portion of long-term regulatory liabilities	(3,365		)	(3,335		)
Other	493			56
Regulatory liabilities, long-term	134,401			132,457
Total Regulatory Liabilities	$	144,555		$	141,072

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

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

(3)  Resulting from the Missouri Clean Energy Initiative and consists of approximately 467 solar rebate applications processed and internal costs as of March 31, 2016 (compared to 262 as of December 31, 2015), resulting in solar rebate-related costs totaling approximately $6.2 million.

(4)  As part of our depreciation rates, we accrue the estimated cost of dismantling and removing plant from service upon retirement. The accrued cost of removal, upon retirement, is reclassified from accumulated depreciation to a regulatory liability. These reclassified amounts are reflected here. See the depreciation discussion under Note 1 and Note 2 Property, Plant and Equipment in our Annual Report on Form 10-K for the fiscal year ended December 31, 2015 for more detail.

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

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Note 4— Risk Management and Derivative Financial Instruments

We engage in hedging activities in an effort to minimize our risk from the volatility of natural gas prices and power cost risk associated with exposure to congestion costs. We enter into both physical and financial contracts with counterparties relating to our future natural gas requirements that lock in prices (with respect to a range of predetermined percentages of our expected future natural gas needs) in an attempt to lessen the volatility in our fuel expenditures and gain predictability.

We began acquiring Transmission Congestion Rights (TCR) in 2013 in an attempt to mitigate the cost of power we purchase from the Southwest Power Pool (SPP) Integrated Marketplace (IM) due to congestion exposure. TCRs entitle the holder to a stream of revenues (or charges) based on the day-ahead congestion on the transmission path. TCRs can be purchased or self-converted using rights allocated based on prior investments made in the transmission system. We recognize that if risk is not timely and adequately balanced or if counterparties fail to perform contractual obligations, actual results could differ materially from intended results.

All derivative instruments are recognized at fair value on the balance sheet. The unrealized losses or gains from derivatives used to hedge our fuel and purchased power costs in our electric segment are recorded in regulatory assets or liabilities. All gains and losses from derivatives related to the gas segment are also recorded in regulatory assets or liabilities. This is in accordance with the Accounting Standards Codification (ASC) guidance on regulated operations, given that those gains or losses are probable of refund or recovery, respectively, through our fuel adjustment mechanisms.

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

As of March 31, 2016 and December 31, 2015, we have recorded the following assets and liabilities representing the fair value of derivative financial instruments, (in thousands):

		March 31,		December 31,
ASSET DERIVATIVES		2016		2015
Hedging instruments	Balance Sheet Classification	Fair Value		Fair Value
Natural gas contracts, gas segment	Current assets	$	18	$	2
	Non-current assets and deferred charges — other	—		16
Natural gas contracts, electric segment	Current assets	—		—
	Non-current assets and deferred charges — other	—		—
Transmission congestion rights, electric segment	Current assets	590		1,293
Total derivatives assets		$	608	$	1,311

		March 31,		December 31,
LIABILITY DERIVATIVES		2016		2015
Hedging instruments	Balance Sheet Classification	Fair Value		Fair Value
Natural gas contracts, gas segment	Current liabilities	$	14	$	282
	Non-current liabilities and deferred credits	51		66
Natural gas contracts, electric segment	Current liabilities	4,729		4,190
	Non-current liabilities and deferred credits	3,822		3,630
Total derivatives liabilities		$	8,616	$	8,168

13

Electric Segment

At March 31, 2016, approximately $4.7 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 March 31, (in thousands):

Non-Designated Hedging Instruments  — Due to Regulatory Accounting Electric Segment	Balance Sheet  Classification of Gain /  (Loss) on Derivative	Amount of Gain / (Loss) Recognized on Balance  Sheet
		Three Months Ended						Twelve Months Ended
		2016			2015			2016			2015
Commodity contracts	Regulatory (assets)/liabilities	$	(1,709	)	$	(2,540	)	$	(6,022	)	$	(11,077	)
Transmission congestion rights	Regulatory (assets)/liabilities	122			1,105			3,987			13,434
Total Electric Segment		$	(1,587	)	$	(1,435	)	$	(2,035	)	$	2,357

Non-Designated Hedging Instruments  — Due to Regulatory Accounting Electric Segment	Statement of Income  Classification of Gain /  (Loss) on Derivative	Amount of Gain / (Loss) Recognized in Income  on Derivative
		Three Months Ended						Twelve Months Ended
		2016			2015			2016			2015
Commodity contracts	Fuel and purchased power expense	$	(1,698	)	$	(1,421	)	$	(8,392	)	$	(3,834	)
Transmission congestion rights	Fuel and purchased power expense	796			3,438			4,826			13,743
Total Electric Segment		$	(902	)	$	2,017		$	(3,566	)	$	9,909

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

As of March 31, 2016, the following volumes and percentage of our anticipated volume of natural gas usage for our electric operations for the remainder of 2016 and for the next four years are shown below at the following average prices per Dekatherm (Dth). We utilize the following procurement guidelines for our electric segment, allowing the flexibility to hedge up to 100% of the current year’s and 80% of any future year’s expected requirements while being cognizant of volume risk. The 80% guideline is an annual target and volumes up to 100% can be hedged in any given month. For years beyond year four, additional factors of long term uncertainty (including with respect to required volumes and counterparty credit) are also considered.

		Dth Hedged				Procurement
Year	% Hedged	Physical	Financial	Average Price		Guidelines
Remainder 2016	56%	2,676,000	3,860,000	$	3.54	Up to 100%
2017	41%	782,900	5,210,000	$	3.35	60%
2018	20%	565,000	2,460,000	$	3.33	40%
2019	10%	—	1,460,000	$	2.96	20%
2020	—	—	—	—		10%

At March 31, 2016, the following transmission congestion rights (TCR) have been obtained to hedge congestion risk in the SPP IM (dollars in thousands):

Year	Monthly MWH  Hedged	$ Value
2016	1,430	$	590

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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 March 31, 2016, we had 1.3 million Dths in storage on the three pipelines that serve our customers. This represents 61% 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 and illustrates our hedged position as of March 31, 2016 (Dth in thousands).

Season	Target % Hedged by September 1	Dth Hedged — Financial	Dth Hedged — Physical	Dth in Storage	Actual % Hedged
Nov. 2016 - Mar. 2017	50%	200,000	—	1,252,281	47%
Nov. 2017 - Mar. 2018	Up to 50%	280,000	—	—	9%
Nov. 2018 - Mar. 2019	Up to 20%	—	—	—	—

A Purchased Gas Adjustment (PGA) clause is included in our rates for our gas segment operations. Therefore, we mark to market any unrealized gains or losses and any realized gains or losses relating to financial derivative contracts to a regulatory asset or regulatory liability account on our balance sheet.

The following table sets forth “mark-to-market” pre-tax gains / (losses) from derivatives not designated as hedging instruments for the gas segment for each of the periods ended March 31 (in thousands).

		Amount of Gain / (Loss)
Non-Designated Hedging	Balance Sheet	Recognized on Balance Sheet
Instruments Due to Regulatory	Classification of Gain or	Three Months Ended						Twelve Months Ended
Accounting — Gas Segment	(Loss) on Derivative	2016			2015			2016			2015
Commodity contracts	Regulatory (assets)/ liabilities	$	(67	)	$	(17	)	$	(497	)	$	(478	)
Total - Gas Segment		$	(67	)	$	(17	)	$	(497	)	$	(478	)

Contingent Features

Certain of our derivative instruments contain provisions that are triggered if we fail to maintain an investment grade credit rating with any relevant credit rating agency. If our debt were to fall below investment grade, the counterparties to the derivative instruments could request increased collateralization on derivative instruments in net liability positions. We had no derivative instruments with the credit-risk-related contingent features in a net liability position on March 31, 2016 and have posted no collateral with counterparties in the normal course of business. Amounts reported as margin deposit assets represent our funds held on deposit for our contracts held with our NYMEX broker and other financial contracts with other counterparties that resulted from us exceeding agreed-upon credit limits established by the counterparties. The following table depicts our margin deposit assets at the dates shown. There were no margin deposit liabilities at these dates.

(in millions)	March 31, 2016		December 31, 2015
Margin deposit assets	$	10.3	$	11.2

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 agreements: (1) the International Swaps and Derivatives Association Agreement, a standardized

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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 March 31, 2016 and December 31, 2015, we did not hold any collateral posted by our counterparties. The only collateral we have posted is our margin deposit assets described above. We have elected not to offset our margin deposit assets against any of our eligible commodity contracts.

Note 5— Fair Value Measurements

The accounting guidance on fair value measurements establishes a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value. These tiers include: (i) Level 1, defined as quoted prices in active markets for identical instruments; (ii) Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and (iii) Level 3, defined as unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions. Our Level 2 fair value measurements consist of both quoted price inputs and inputs that are derived principally from or corroborated by observable market data.

The guidance also requires that the fair value measurements of assets and liabilities reflect the nonperformance risk of counterparties and the reporting entity, as applicable. Therefore, using credit default spreads, we factored the impact of our own credit standing and the credit standing of our counterparties, as well as any potential credit enhancements (e.g. collateral) into the consideration of nonperformance risk for both derivative assets and liabilities. The results of this analysis were not material to the financial statements.

Our TCR positions, which are acquired on the SPP IM, are valued using the most recent monthly auction clearing prices. Our commodity contracts are valued using the market value approach on a recurring basis. The following fair value hierarchy table presents information about our TCR and commodity contracts measured at fair value as of March 31, 2016 and December 31, 2015 (in thousands):

	Fair Value Measurements at Reporting Date Using
Description	Assets/(Liabilities) at Fair Value			Quoted Prices in Active Markets for Identical Assets/(Liabilities) (Level 1)			Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
				March 31, 2016
Derivative assets	$	608		$	18		$	590	$	—
Derivative liabilities	$	(8,616	)	$	(8,616	)	$	—	$	—
				December 31, 2015
Derivative assets	$	1,311		$	18		$	1,293	$	—
Derivative liabilities	$	(8,168	)	$	(8,168	)	$	—	$	—

*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 both March 31, 2016 and December 31, 2015 was $851 million. The fair market value at March 31, 2016 was approximately $856 million as compared to approximately $815 million at December 31, 2015. These estimates were based on a bond pricing model, utilizing inputs classified as Level 2 in the fair value hierarchy, which include the quoted market prices for the same or similar issues or on the current rates offered to us for debt of the same remaining maturities. The estimated fair market value may not represent the actual value that could have been realized as of March 31, 2016 or that will be realizable in the future.

Note 6— Financing

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

The credit facility requires our total indebtedness to be less than 65.0% of our total capitalization at the end of each fiscal quarter and a failure to maintain this ratio will result in an event of default under the credit facility and will prohibit us from borrowing funds thereunder. As of March 31, 2016, we were in compliance with this covenant as our ratio of total indebtedness was 52% of our total capitalization. This credit facility is also subject to cross-default if we default on more than $25 million in the aggregate on our other indebtedness. As of March 31, 2016, we were not in default under any of such other indebtedness.

The credit agreement does not legally restrict the use of our cash in the normal course of operations. There were no outstanding borrowings under the agreement at March 31, 2016; however, $19.0 million was used to back up our outstanding commercial paper.

Note 7— Commitments and Contingencies

Legal Proceedings

We are a party to various claims and legal proceedings arising out of the normal course of our business. We regularly analyze this information, and provide accruals for any liabilities, in accordance with the guidelines presented in the ASC on accounting for contingencies. In the opinion of management, it is not probable, given the company’s defenses, that the ultimate outcome of these claims and lawsuits will have a material adverse effect upon our financial condition, or results of operations or cash flows.

Proceedings in connection with the pending merger with Liberty Central

On March 24, 2016, a purported shareholder of Empire filed a complaint styled as a class action lawsuit in the District Court for the 3rd Judicial District, in Shawnee County, Kansas. The complaint alleges that Empire’s Board of Directors breached its fiduciary duties in agreeing to the Merger Agreement by, among other things, conducting an inadequate sales process and failing to obtain adequate consideration, having an interest in completing the Merger, and failing to make adequate disclosures in the proxy statement. The complaint seeks various relief, including an injunction against the Merger. The complaint also alleges that Empire, APUC, Liberty Central and Merger Sub aided and abetted such alleged breaches.

The outcome of the lawsuit cannot be predicted with any certainty. A preliminary injunction could delay or jeopardize the completion of the Merger, and an adverse judgment granting permanent injunctive relief could indefinitely enjoin completion of the Merger. All of the defendants believe that the claims asserted against them in the lawsuit are without merit.

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Coal, Natural Gas and Transportation Contracts

The following table sets forth our firm physical gas, coal and transportation contracts for the periods indicated as of March 31, 2016 (in millions).

	Firm physical gas and transportation contracts		Coal and coal transportation contracts
April 1, 2016 through December 31, 2016	$	21.8	$	12.2
January 1, 2017 through December 31, 2018	37.4		26.9
January 1, 2019 through December 31, 2020	28.8		10.5
January 1, 2021 and beyond	45.7		—

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. The firm physical gas and transportation commitments are detailed in the table above.

We have coal supply agreements and transportation contracts in place to provide for the delivery of coal to the plants. These contracts are written with Force Majeure clauses that enable us to reduce tonnages or cease shipments under certain circumstances or events. These include mechanical or electrical maintenance items, acts of God, war or insurrection, strikes, weather and other disrupting events. This reduces the risk we have for not taking the minimum requirements of fuel under the contracts. The minimum requirements for our coal and coal transportation contracts as of March 31, 2016, are detailed in the table above.

Purchased Power

We have three purchased power agreements.

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 agreement for the purchase of an additional 50 megawatts of capacity from Plum Point. Commitments under this agreement are approximately $275.1 million through August 31, 2039, the end date of the agreement.

We have a long-term purchased power agreement, which expires in 2028, 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 long-term purchased power agreement, which expires in 2020, with Elk River Windfarm, LLC, owned by IBERDROLA RENEWABLES, Inc., to purchase the energy generated at the 150-megawatt Elk River Windfarm located in Butler County, Kansas. Annual payments are contingent upon output of the facility and can range from zero to a maximum of approximately $16.9 million based on a 20-year average cost.

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

New Construction

In April 2016 we completed the conversion of Riverton Unit 12 from a simple cycle combustion turbine to a combined cycle unit. The conversion included the installation of a heat recovery steam generator (HRSG), steam turbine generator, auxiliary boiler, cooling tower, and other auxiliary equipment. Construction costs through March 31, 2016 were $163.4 million for the project to date, excluding AFUDC. Final cost is estimated to range from $165 million to $175 million, excluding AFUDC. This amount was included in our five-year capital expenditure plan.

See “Environmental Matters” below for more information.

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Leases

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

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

The gross amount of assets recorded under capital leases total $5.3 million at March 31, 2016.

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. While we are not in a position to accurately estimate compliance costs for any new requirements, we expect these costs to be material, although recoverable in rates.

Compliance Plan

In order to comply with current and forthcoming environmental regulations, we implemented our compliance plan and strategy (2013 Compliance Plan), which largely followed our Integrated Resource Plan (IRP) filed with the MPSC in mid-2013. On April 1, 2016, we filed our updated IRP, reflecting the completion of our 2013 Compliance Plan. The Mercury Air Toxic Standards (MATS) and the Clean Air Interstate Rule (CAIR), replaced by the Cross State Air Pollution Rule (CSAPR), are the drivers behind our Compliance Plan and its implementation schedule. We anticipate compliance costs associated with the MATS, CAIR and CSAPR regulations to continue to be recoverable in our rates.

The following list summarizes the most significant environmental regulations affecting our operations:

Regulations

Air Emissions - NOx and SO2

CAIR (Clean Air Interstate Rule)

CSAPR (Cross State Air Pollution Rule)

MATS (Mercury Air Toxic Standards)

NAAQS (National Ambient Air Quality Standards)

Greenhouse Gases (GHGs) — CO2

Surface Impoundments

Coal Ash Impoundments:

Asbury Power Plant

Riverton (capped and closed in 2014 as industrial (coal combustion waste) landfill)

Water Discharges

MATS: In June 2015, the U.S. Supreme Court remanded the MATS back to the D.C. Circuit Court, holding that the EPA must consider cost (including cost of compliance) before deciding whether a regulation is appropriate and necessary. The court noted that it will be up to the EPA to decide within the limits of reasonable interpretation how to account for cost. The EPA’s determination claimed that considering cost does not alter the agency’s conclusion that it is appropriate and necessary to regulate coal and oil-fired electric utility steam generating units (EGUs) under the regulation. The U.S.

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Court of Appeals rejected challenges to the MATS in December 2015 and the MATS remains in effect. The final Technical Corrections Rule was signed March 17, 2016.

Greenhouse Gases: On August 3, 2015, the EPA released the final rule for limiting carbon emissions from existing power plants. The “Clean Power Plan” (CPP) requires a 32% 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. States will choose between two plan types to meet their goals: an emission standards plan which includes source-specific requirements impacting affected power plants or a state measures plan which includes a mixture of measures implemented by the state.

On February 9, 2016, the Supreme Court ordered a stay on the CPP. Twenty-seven states and numerous industry groups have challenged the CPP’s legality in the D.C. Circuit. The stay will remain in effect until the court resolves the legal challenges to the CPP and either the Supreme Court decides not to review the D.C. Circuit’s decision or the Supreme Court issues its own opinion. Other than the cancellation of the initial submittal deadline this September, the EPA has not made any definitive statements regarding whether CPP timelines may change under the stay. The ultimate cost of compliance cannot be determined at this time because of the uncertainties regarding the final outcome of the GHG regulations, including the legal challenges thereto, and the compliance methods yet to be chosen by the jurisdictions in which we operate. In any case, we expect the cost of complying with any such regulations to be recoverable in our rates.

Surface Impoundments: On September 30, 2015, the EPA finalized a revision of the Clean Water Act (CWA) Steam Electric Effluent Limitation Guidelines (ELGs) for coal-fired power plants. The new rule sets technology-based ELGs based on the nature of the pollutants being discharged and the facilities involved. As published, beginning in November 2018, the EPA and states would incorporate the new standards into all wastewater discharge permits, including permits for coal ash impoundments. We do not have sufficient information at this time to estimate additional costs at each facility that will result from the new standards to be in effect no later than December 2023.

Effective October 19, 2015, the EPA established a final rule to regulate the disposal of coal combustion residuals (CCRs) as a non-hazardous solid waste under subtitle D of the Resource Conservation and Recovery Act (RCRA). We expect compliance with both the CCR and ELG rule to result in the need to construct a new landfill and the conversion of existing bottom ash handling from a wet to a dry system at a potential cost of up to $15 million at our Asbury Power Plant. We expect resulting costs to be recoverable in our rates. Final closure of the existing ash impoundment, for which an asset retirement obligation of $5.4 million has been recorded, is anticipated after the new landfill is operational. Separately, an asset retirement obligation of $4.4 million has been recorded for our interest in the coal ash impoundment at the Iatan Generating Station.

On February 1, 2016, a construction permit application was submitted to the Missouri Department of Natural Resources’ Solid Waste Management Program (SWMP) for a new utility waste landfill adjacent to the Asbury plant. The application has been determined to be complete and a technical review by the SWMP is in progress. Approval of the final construction permit for the CCR waste landfill is expected by February 2017.

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 EPA final rule under the CWA Section 316(b) for existing cooling water intake structures became effective on October 14, 2014. An industry coalition has filed an appeal of the rule in the Fifth Circuit and additional court challenges are expected. We expect the regulations to have no future impact at Riverton as the new intake structure design and installed cooling tower, as part of the Unit 12 conversion, meets the regulatory requirement for aquatic life protections. Impacts at Iatan 1 could range from flow velocity reductions or traveling screen modifications for fish handling to installation of a closed cycle cooling tower retrofit.  Iatan Unit 2 and Plum Point Unit 1 are covered by the regulation, but were constructed with cooling towers, the proposed Best Technology Available. We expect them to be unaffected or minimally affected by the final rule.

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Renewable Energy

The Clean Energy Initiative (Proposition C) requires Empire and other investor-owned utilities in Missouri to generate or purchase electricity from renewable energy sources, such as solar, wind, biomass and hydro power, or purchase Renewable Energy Credits (RECs), in amounts equal to at least 5% of retail sales in 2014-2017, at least 10% in 2018-2020 and at least 15% by 2021. We are currently in compliance with this regulatory requirement as a result of generation from our Ozark Beach Hydroelectric Project and purchased power agreements previously mentioned with Cloud County Windfarm, LLC and Elk River Windfarm, LLC. Proposition C also requires that 2% of the energy from renewable energy sources must be solar. On May 6, 2015, the MPSC approved tariffs we filed on May 5, 2015 to establish solar rebate payment procedures and revise our net metering tariffs to accommodate the payment of solar rebates. As of March 31, 2016, we had processed 467 solar rebate applications resulting in solar rebate-related costs totaling approximately $6.2 million under the new tariff. We have recorded the $6.2 million as a regulatory asset (See Note 3 — Regulatory Matters). The law provides a number of methods that may be utilized to recover the associated expenses. We expect any costs to be recoverable in rates.

Legislation was recently adopted that altered the Kansas renewable portfolio standard (RPS), ending all mandatory requirements in 2015. The mandate, which required 20% of our Kansas retail customer peak capacity requirements to be sourced from renewables by 2020, has been changed to a voluntary goal. We are currently in compliance as a result of purchased power agreements with Cloud County Windfarm, LLC and Elk River Windfarm, LLC.

Note 8 — Retirement and Other Employee Benefits

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

	Three months ended March 31,
	Pension						SERP						OPEB
	2016			2015			2016			2015			2016			2015
Service cost	$	1,949		$	1,883		$	45		$	43		$	813		$	920
Interest cost	2,633			2,503			108			92			1,156			1,164
Expected return on plan assets	(3,465		)	(3,390		)	—			—			(1,374		)	(1,312		)
Amortization of prior service cost (1)	(157		)	(157		)	(3		)	(11		)	(253		)	(253		)
Amortization of net actuarial loss (1)	2,106			2,345			139			140			258			681
Net periodic benefit cost	$	3,066		$	3,184		$	289		$	264		$	600		$	1,200

	Twelve months ended March 31,
	Pension						SERP						OPEB
	2016			2015			2016			2015			2016			2015
Service cost	$	7,508		$	6,722		$	161		$	167		$	3,606		$	2,914
Interest cost	10,408			10,589			398			393			4,663			4,442
Expected return on plan assets	(13,643		)	(13,173		)	—			—			(5,258		)	(4,916		)
Amortization of prior service cost (1)	(630		)	156			(35		)	(17		)	(1,011		)	(1,011		)
Amortization of net actuarial loss (1)	9,795			7,308			596			539			2,324			1,420
Net periodic benefit cost	$	13,438		$	11,602		$	1,120		$	1,082		$	4,324		$	2,849

(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. Employees hired after June 1, 2014 will not receive a subsidy for healthcare benefits upon retirement.

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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 $12.4 million during 2016. 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 $2.6 million during 2016. The actual minimum funding requirements for both pension and OPEB will be determined based on the results of the actuarial valuations.

Note 9 — Equity Compensation

Our time-vested restricted stock awards and performance-based restricted stock awards are valued as liability awards, in accordance with fair value guidelines. We allow qualified individuals 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 2016 (the effect of which is included in the table below). We had unrecognized compensation expense of $2.3 million as of March 31, 2016 which will be recognized over the remaining requisite service period.

We recognized the following amounts in compensation expense and tax benefits for all of our stock-based awards and programs for the applicable periods ended March 31 (in thousands):

	Three Months Ended				Twelve Months Ended
	2016		2015		2016		2015
Compensation expense	$	2,076	$	742	$	5,614	$	3,081
Tax benefit recognized	777		271		2,082		1,127

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 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. In addition, if a change in control occurs during the vesting period, a pro-rata portion of the time-vested restricted stock awards will vest upon such change in control, and any portion of such awards that remains unvested immediately after the change in control will be forfeited.

A summary of time vested restricted stock activity under the plan for 2015 and 2016 is presented in the table below:

	2016				2015
			Weighted				Weighted
	Number of		Average Grant		Number of		Average Grant
	shares		Date Fair Value		shares		Date Fair Value
Outstanding at January 1,	55,600		$	24.60	41,000		$	21.89
Granted	18,400		29.53		19,000		30.40
Distributed	(18,500	)	21.36		(1,654	)	21.92
Forfeited shares	0				(2,746	)	25.91
Outstanding at March 31	55,500		$	27.31	55,600		$	24.60

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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.

If employment terminates during the performance period because of death, retirement, or disability, the individual is entitled to a pro-rata portion of the performance-based restricted stock awards such individual would otherwise have earned. If employment is terminated during the performance period for reasons other than those listed above, the performance-based restricted stock awards will be forfeited on the date of the termination unless the Compensation Committee of the Board of Directors determines, in its sole discretion, that the individual is entitled to a pro-rata portion of such award.  In addition, if a change in control occurs during the performance period, a pro-rata portion of the target performance-based restricted stock awards will vest and be distributed upon such change in control. At the end of the performance period, the number of shares earned, determined without regard to the special change in control vesting provisions will be determined and such amount, less the number of shares distributed upon the change in control, shall be distributed.

In connection with the Merger Agreement, we amended outstanding performance-based restricted stock awards to provide that, effective upon and subject to the occurrence of the Merger under the Merger Agreement, each performance-based restricted stock award outstanding immediately prior to the effective time of the Merger will be converted into the right to receive a lump sum in cash equal to the merger consideration under the Merger Agreement, multiplied by the target number of shares under the award.  (See Note 13 for further discussion of the Merger Agreement).

Non-vested performance-based restricted stock awards (based on target number) as of March 31, 2016 and 2015 and changes during the three months ended March 31, 2016 and 2015 were as follows:

	2016				2015
	Number of shares		Weighted Average Grant Date Price		Number of shares		Weighted Average Grant Date Price
Outstanding at January 1,	69,021		$	24.38	63,300		$	21.74
Target shares granted	22,400		$	29.53	21,800		$	30.40
Shares issued in excess of target	18,403		$	21.36	3,653		$	30.55
Shares awarded	(43,036	)	$	21.36	(13,653	)	$	30.55
Forfeited shares	—		$	—	(6,079	)	$	24.10
Target shares not awarded	—		$	—	—		$	—
Granted, nonvested at March 31,	66,788		$	27.22	69,021		$	24.38

Stock Unit Plan for Directors

Our Stock Unit Plan for directors (Stock Unit Plan) provides a stock-based compensation program for directors.  This plan enhances our ability to attract and retain competent and experienced directors and allows the directors the opportunity to accumulate compensation in the form of common stock units. The Stock Unit Plan also provides directors the opportunity to convert previously earned cash retirement benefits to common stock units.  All eligible directors who had benefits under the prior cash retirement plan converted their cash retirement benefits to common stock units.

Each common stock unit earns dividends in the form of common stock units and can be redeemed for shares of common stock.  In connection with the Merger Agreement, we amended the Stock Unit Plan to provide that, effective upon and subject to the occurrence of the Merger under the Merger Agreement, each stock unit outstanding immediately prior to the effective time of the Merger will be converted into the right to receive in cash the merger consideration under the Merger Agreement, with interest at the prime rate from the effective time of the Merger until the payment date under the plan. (See Note 13 for further discussion of the Merger Agreement).

The number of units granted annually is computed by dividing an annual credit (determined by the Compensation Committee) by the fair market value of our common stock on January 1 of the year the units are granted. Common stock unit dividends are computed based on the fair market value of

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our stock on the dividend’s record date.  We record the related compensation expense at the time we make the accrual for the directors’ benefits as the directors provide services. Shares accrued to directors’ accounts and shares available for issuance under this plan at March 31, 2016 and 2015 are shown in the table below:

	2016	2015
Shares accrued to directors’ accounts	160,124	164,085
Shares available for issuance	656,737	685,996

Units accrued for service and dividends as well as units redeemed for common stock at March 31, 2016 and 2015 are shown in the table below:

	2016	2015
Units accrued for service and dividends	23,698	25,187
Units redeemed for common stock	21,246	28,991

Note 10 - Regulated Operating Expense

The following table sets forth the major components comprising “regulated operating expenses” under “Operating revenue deductions” on our consolidated statements of income (in thousands) for all periods presented ended March 31:

	Three Months Ended		Three Months Ended		Twelve Months Ended		Twelve Months Ended
	2016		2015		2016		2015
Electric transmission and distribution expense	$	6,836	$	7,100	$	28,629	$	28,221
Natural gas transmission and distribution expense	706		677		2,727		2,365
Power operation expense (other than fuel)	4,053		5,317		16,999		17,415
Customer accounts and assistance expense	2,731		2,704		10,965		11,106
Employee pension expense (1)	2,625		2,684		10,727		10,648
Employee healthcare expense (1)	2,245		2,234		10,173		9,656
General office supplies and expense	4,339		2,834		15,944		13,666
Administrative and general expense	4,116		4,556		14,423		14,716
Allowance for uncollectible accounts	79		327		1,833		2,975
Miscellaneous expense	115		118		425		603
Total	$	27,845	$	28,551	$	112,845	$	111,371

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

Note 11— Segment Information

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

	For the quarter ended March 31,
	2016
	Electric		Gas		Other		Eliminations			Total
Statement of Income Information
Revenues	$	134,363	$	15,113	$	2,184	$	(345	)	$	151,315
Depreciation and amortization	18,916		996		491		—			20,403
Federal and state income taxes	7,568		799		273		—			8,640
Operating income	20,507		2,293		443		—			23,243
Interest income	4		10		24		(29		)	9
Interest expense	10,688		969		—		(29		)	11,628
Income from AFUDC (debt and equity)	2,754		4		—		—			2,758
Net income	12,240		1,326		443		—			14,009
Capital Expenditures	$	33,167	$	863	$	419	$	—		$	34,449

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	For the quarter ended March 31,
	2015
	Electric		Gas		Other		Eliminations			Total
Statement of Income Information
Revenues	$	142,641	$	19,818	$	2,430	$	(345	)	$	164,544
Depreciation and amortization	18,589		972		459		—			20,020
Federal and state income taxes	7,202		1,126		443		—			8,771
Operating income	21,214		2,788		711		—			24,713
Interest income	2		12		9		(12		)	11
Interest expense	10,091		965		—		(12		)	11,044
Income from AFUDC (debt and equity)	1,541		1		—		—			1,542
Net income	12,096		1,822		719		—			14,637
Capital Expenditures	$	52,263	$	683	$	609	$	—		$	53,555

	For the twelve months ended March 31,
	2016
	Electric		Gas		Other		Eliminations			Total
Statement of Income Information
Revenues	$	546,808	$	36,997	$	9,918	$	(1,379	)	$	592,344
Depreciation and amortization	75,059		3,947		1,927		—			80,933
Federal and state income taxes	31,489		473		1,719		—			33,681
Operating income	87,165		4,657		2,756		—			94,578
Interest income	135		35		62		(88		)	144
Interest expense	41,903		3,871		—		(88		)	45,686
Income from AFUDC (debt and equity)	8,893		17		—		—			8,910
Net income	52,384		791		2,794		—			55,969
Capital Expenditures	$	150,016	$	5,369	$	2,032	$	—		$	157,417

	For the twelve months ended March 31,
	2015
	Electric		Gas		Other		Eliminations			Total
Statement of Income Information
Revenues	$	582,043	$	47,051	$	9,437	$	(1,330	)	$	637,201
Depreciation and amortization	69,547		3,822		1,895		—			75,264
Federal and state income taxes	32,692		1,519		1,660		—			35,871
Operating income	86,176		6,289		2,760		—			95,225
Interest income	7		25		27		(39		)	20
Interest expense	38,635		3,863		—		(39		)	42,459
Income from AFUDC (debt and equity)	9,408		59		—		—			9,467
Net Income	55,679		2,457		2,699		—			60,835
Capital Expenditures	$	218,696	$	5,348	$	2,303	$	—		$	226,347

	As of March 31, 2016
($-000’s)	Electric		Gas(1)		Other		Eliminations			Total
Balance Sheet Information
Total assets	$	2,335,112	$	129,987	$	38,417	$	(52,590	)	$	2,450,926

(1) Includes goodwill of $39,492.

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	As of December 31, 2015
($-000’s)	Electric		Gas(1)		Other		Eliminations			Total
Balance Sheet Information
Total assets	$	2,331,705	$	127,359	$	38,299	$	(50,718	)	$	2,446,645

(1) Includes goodwill of $39,492.

Note 12— Income Taxes

The following table shows our provision for income taxes (in millions) and our consolidated effective federal and state income tax rates for the applicable periods ended March 31,:

	Three Months Ended						Twelve Months Ended
	2016			2015			2016			2015
Consolidated provision for income taxes	$	8.6		$	8.8		$	33.7		$	35.9
Consolidated effective federal and state income tax rates	38.1		%	37.5		%	37.6		%	37.1		%

The effective income tax rate for the three and twelve month periods ended March 31, 2016 is higher than comparable periods in 2015 primarily due to lower equity AFUDC income in 2016 compared to 2015.

We do not have any unrecognized tax benefits as of March 31, 2016. We did not recognize any significant interest or penalties in any of the periods presented. We do not expect any significant changes to our unrecognized tax benefits over the next twelve months.

The “Protecting Americans from Tax Hikes” Act (the “Act”) was signed into law on December 18, 2015. The Act restored several expired business tax provisions, including bonus depreciation for 2015. Because of the reinstatement of bonus depreciation, we anticipate making no material income tax payments in 2016.

We generated $74.1 million of tax NOLs during 2014, mainly due to bonus depreciation. We intend to carry forward these tax NOLs, which, if unused, will expire in 2034. We estimate that we will utilize approximately $38.0 million of the 2014 tax NOLs on our 2015 return when filed.  As of March 31, 2016, we estimate there is $13.5 million of deferred tax assets remaining to be utilized related to the tax NOLs.

In 2010, we received $17.7 million of investment tax credits based on our investment in Iatan 2, which, if unused, will expire in 2030. We utilized $9.0 million of these credits on our 2013 tax return.  Due to the passage of the Act, we estimate we will not be able to use the remaining credits on our 2015 tax return, but expect to use them to offset future income tax liabilities. The tax credits will have no significant income statement impact because they will flow to our customers as we amortize the tax credits over the life of the plant.

On September 13, 2013, the IRS and the Treasury Department released final regulations under Sections 162(a) and 263(a) on the deduction and capitalization of expenditures related to tangible property. These regulations applied to tax years beginning on or after January 1, 2014, and we filed a Form 3115 with the IRS to change our tax accounting method to comply with the regulations.  As a result, we deducted approximately $29 million on our 2014 income tax return under IRS Code Section 481(a) as an adjustment required by the change in tax accounting method.

Our 2014 income tax return included another tax accounting method change regarding the deductibility of the Voluntary Employee Benefit Association (VEBA) plan activity. As a result, we deducted approximately $14 million as an adjustment required by the change in tax method of accounting.  These changes did not have a material impact on the effective tax rate.

Note 13 — Mergers and Acquisitions

Pending Merger with Liberty Utilities (Central) Co. and Liberty Sub Corp.

On February 9, 2016, Empire entered into an Agreement and Plan of Merger (the Merger Agreement) with Liberty Utilities (Central) Co., a Delaware corporation (Liberty Central), and Liberty

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Sub Corp., a Kansas corporation (Merger Sub), providing for the merger of Merger Sub with and into Empire, with Empire surviving the Merger as a wholly-owned subsidiary of Liberty Central (the Merger). Pursuant to the Merger Agreement, at the effective time of the Merger, each issued and outstanding share of Empire common stock (other than any shares owned by Empire or Algonquin Power & Utilities Corp. (APUC) or any of their respective subsidiaries or any shares for which appraisal rights have been perfected) will be cancelled and converted automatically into the right to receive $34.00 in cash, without interest.

The closing of the Merger is subject to certain conditions, including, among others, approval of Empire shareholders, expiration or termination of the applicable Hart-Scott-Rodino Act waiting period and receipt of all required regulatory approvals and consents, including from the Federal Energy Regulatory Commission, the Federal Communications Commission, the Arkansas Public Service Commission, the Kansas Corporation Commission, the Missouri Public Service Commission, the Oklahoma Corporation Commission and the Committee on Foreign Investment in the United States, which approvals and consents shall not, individually or in the aggregate, have or be reasonably likely to have a material adverse effect on the business, properties, financial condition or results of operations of Liberty Utilities Co. and its subsidiaries (including Empire and its subsidiaries), taken as a whole.

If Empire shareholders do not approve the Merger, or the Merger is not consummated by February 9, 2017, the Merger Agreement may terminate, although it may be extended six months in order to obtain certain required regulatory approvals. The Merger Agreement also provides for certain other termination rights for both Empire and Liberty Central. If either party terminates the Merger Agreement because Empire’s board of directors changes its recommendation, or, if within nine months after the termination of the Merger Agreement under certain circumstances, Empire shall have entered into a definitive agreement with respect to, or consummated, an alternative transaction, Empire must pay Liberty Central a termination fee of $53.0 million.  If the Merger Agreement is terminated under certain other circumstances, including the failure to obtain required regulatory approvals, failure to consummate the Merger after all closing conditions have been satisfied and a financing failure has occurred or a breach by Liberty Central of its regulatory cooperation covenants, Liberty Central must pay Empire a termination fee of $65.0 million.

Simultaneously with the execution of the Merger Agreement, Liberty Central delivered to Empire a guarantee agreement (the Guarantee Agreement) executed by APUC, the parent of Liberty Utilities Co.  The Guarantee Agreement provides for an unconditional and irrevocable guarantee by APUC of the full and prompt payment and performance, when due, of all obligations of Liberty Central and Merger Sub under the Merger Agreement.

In connection with entering into the Merger Agreement, Empire has incurred approximately $4.5 million of transaction costs as of March 31, 2016. We expect that the total transaction costs will be approximately $15 to $17 million, with approximately 50% payable in 2016 (assuming a 2017 closing date), of which $4.2 million was incurred in the first quarter of 2016.

Item 2.  Management’s Discussion and Analysis of Financial Condition and Results of Operations

EXECUTIVE SUMMARY

We operate our businesses as three segments: electric, gas and other. The Empire District Electric Company (EDE) is an operating public utility engaged in the generation, purchase, transmission, distribution and sale of electricity in parts of Missouri, Kansas, Oklahoma and Arkansas, including the sale of wholesale energy to four towns in Missouri and Kansas. As part of our electric segment, we also provide water service to three towns in Missouri. The Empire District Gas Company (EDG) is our wholly owned subsidiary which provides natural gas distribution to customers in 48 communities in northwest, north central and west central Missouri. Our other segment consists of our fiber optics business.

During the twelve months ended March 31, 2016, our gross operating revenues were derived as follows:

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Electric segment sales*	92.3	%
Gas segment sales	6.3
Other segment sales	1.4

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

Pending Merger with Liberty Utilities (Central) Co. and Liberty Sub Corp.

On February 9, 2016, Empire entered into an Agreement and Plan of Merger (the Merger Agreement) with Liberty Utilities (Central) Co., a Delaware corporation (Liberty Central), and Liberty Sub Corp., a Kansas corporation (Merger Sub), providing for the merger of Merger Sub with and into Empire, with Empire surviving the Merger as a wholly-owned subsidiary of Liberty Central (the Merger). Pursuant to the Merger Agreement, at the effective time of the Merger, each issued and outstanding share of Empire common stock (other than any shares owned by Empire or Algonquin Power & Utilities Corp. (APUC)) or any of their respective subsidiaries or any shares for which appraisal rights have been perfected) will be cancelled and converted automatically into the right to receive $34.00 in cash, without interest. See Note 13 of “Notes to Consolidated Financial Statements (Unaudited)” for further information. The foregoing description of the Merger, the Merger Agreement and the Guarantee is not a complete description thereof and is qualified in its entirety by reference to the full text of the Merger Agreement and the Guarantee. Copies of the Merger Agreement and the Guarantee were included in a Form 8-K filed with the SEC on February 9, 2016 and in Empire’s Proxy statement filed with the SEC on May 3, 2016.

Following the announcement of the Merger Agreement, a purported shareholder of Empire filed a complaint styled as a class action lawsuit which complaint alleges that Empire’s Board of Directors breached its fiduciary duties in agreeing to the Merger Agreement by, among other things, conducting an inadequate sales process and failing to obtain adequate consideration, having an interest in completing the Merger, and failing to make adequate disclosures in the proxy statement. The complaint seeks various relief, including an injunction against the Merger. The complaint also alleges that Empire, APUC, Liberty Central and Merger Sub aided and abetted such alleged breaches. See Note 7 of “Notes to Consolidated Financial Statements (Unaudited).”

On March 16, 2016, we filed joint applications in all four states in which we have electric operations (Missouri, Oklahoma, Kansas and Arkansas) and with the FERC requesting approval of the Merger.

Earnings

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

	Three Months Ended				Twelve Months Ended
	2016		2015		2016		2015
Basic and diluted earnings per weighted average share of common stock	$	0.32	$	0.34	$	1.28	$	1.40

Electric and gas earnings were negatively impacted by milder weather in the first quarter of 2016 as compared to the same period in 2015. Electric segment gross margin, however, increased during the quarter ending March 31, 2016 compared to the 2015 quarter, reflecting increased electric rates for our Missouri customers effective July 26, 2015. The impact of mild weather, as well as increased depreciation and interest expense offset the positive rate impact. Also negatively impacting earnings in the first quarter of 2016 were approximately $4.2 million of merger related expenses.

Electric and gas earnings for the twelve month period ended March 31, 2016 were also negatively impacted by milder weather in the first quarter of 2016 and the fourth quarter of 2015 as compared to the same periods last year. Electric segment gross margin, however, increased during the twelve months ended March 31, 2016 compared to the same period in 2015, reflecting increased electric rates for our Missouri customers effective July 26, 2015 and improved customer counts. The impact of mild weather, as well as increased regulated operating and maintenance expenses,

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property taxes, interest expense, depreciation expense and reduced AFUDC, negatively impacted 2016 results. Also negatively impacting earnings for the twelve month period ended March 31, 2016 were approximately $4.5 million of merger related expenses.

The table below sets forth a reconciliation of basic and diluted earnings per share (EPS) between the three months and twelve months ended March 31, 2015 and March 31, 2016, which is a non-GAAP presentation. The economic substance behind our non-GAAP EPS measure is to present the after tax impact of significant items and components of the statement of income on a per share basis before the impact of additional stock issuances. The dilutive effect of additional shares issued included in the table reflects the estimated impact of all shares issued during the periods ended March 31.

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

In addition, although a non-GAAP presentation, we believe the presentation of gross margin (in the table below and elsewhere in this report) is useful to investors and others in understanding and analyzing changes in our electric operating performance from one period to the next, and have included the analysis as a complement to the financial information we provide in accordance with GAAP. We define electric gross margin as electric revenues less fuel and purchased power costs. We define gas gross margin as gas operating revenues less cost of gas in rates. This reconciliation and margin information may not be comparable to other companies’ presentations or more useful than the GAAP presentation included in the statement of income. We also note that this presentation does not purport to be an alternative to EPS determined in accordance with GAAP as a measure of operating performance or any other measure of financial performance presented in accordance with GAAP. Management compensates for the limitations of using non-GAAP financial measures by using them to supplement GAAP results to provide a more complete understanding of the factors and trends affecting the business than GAAP results alone.

	Three Months Ended			Twelve Months Ended
Earnings Per Share — 2015	$	0.34		$	1.40
Gross Margins
Electric segment	$	0.04		$	0.21
Gas segment	(0.01		)	(0.04		)
Other segment	0.00			0.01
Total Gross Margin	0.03			0.18
Operating — electric segment	0.01			(0.01		)
Operating —gas segment	0.00			(0.01		)
Operating —other segment	0.00			(0.01		)
Maintenance and repairs	0.00			(0.02		)
Merger related expenses	(0.06		)	(0.06		)
Depreciation and amortization	(0.01		)	(0.08		)
Other taxes	0.00			(0.02		)
AFUDC	0.02			(0.01		)
Change in effective income tax rates	0.00			(0.01		)
Interest charges	(0.01		)	(0.05		)
Other income and deductions	0.00			(0.01		)
Dilutive effect of additional shares issued	0.00			(0.01		)
Earnings Per Share — 2016	$	0.32		$	1.28

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Recent Activities

Integrated Resource Plan

We filed our most recent Integrated Resource Plan (IRP) with the MPSC on April 1, 2016. The IRP analysis of future loads and resources is normally conducted once every three years. This IRP reflects the completion of our 2013 Compliance Plan discussed in Note 7 of “Notes to Consolidated Financial Statements (Unaudited)”.

Riverton Unit 12 Combined Cycle Project

As part of our environmental Compliance Plan, we completed the conversion of Riverton Unit 12 from a simple cycle combustion turbine to a combined cycle unit in April 2016. The conversion included the installation of a heat recovery steam generator (HRSG), steam turbine generator, auxiliary boiler, cooling tower, and other auxiliary equipment. All in-service testing was completed and results verified internally by April 30, 2016. Riverton Unit 12 Combined Cycle was offered into the SPP IM and placed in-service on May 1, 2016. See Note 7 of “Notes to Consolidated Financial Statements (Unaudited).”

Regulatory Matters

Our rate cases, as we reported in our Annual Report on Form 10-K for the year ended December 31, 2015, remain unchanged.

See “Rate Matters” below for more information.

RESULTS OF OPERATIONS

The following discussion analyzes significant changes in the results of operations for the three-month and twelve-month periods ended March 31, 2016, compared to the same periods ended March 31, 2015.

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

	Three Months Ended				Twelve Months Ended
	2016		2015		2016		2015
Electric	$	12.3	$	12.1	$	52.4	$	55.7
Gas	1.3		1.8		0.8		2.4
Other	0.4		0.7		2.8		2.7
Net income	$	14.0	$	14.6	$	56.0	$	60.8

Electric Segment

Electric operating revenues comprised approximately 88.8% of our total operating revenues during the first quarter of 2016.

Sales, Revenues and Gross Margin

KWh Sales

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

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	kWh Sales
	3 Months	3 Months			12 Months	12 Months
	Ended	Ended	%		Ended	Ended	%
Customer Class	2016	2015	Change(1)		2016	2015	Change(1)
Residential	507.7	589.9	(13.9	)%	1,754.1	1,898.7	(7.6	)%
Commercial	360.0	377.2	(4.6	)	1,560.2	1,572.5	(0.8	)
Industrial	247.8	245.7	0.8		1,066.5	1,040.2	2.5
Wholesale on-system	79.0	81.7	(3.3	)	328.1	333.9	(1.7	)
Other(2)	34.1	34.3	(0.8	)	130.8	127.2	2.8
Total on-system sales	1,228.6	1,328.8	(7.5	)	4,839.7	4,972.5	(2.7	)

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

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

KWh sales for our on-system customers decreased 7.5% during the first quarter of 2016 as compared to the first quarter of 2015, primarily due to decreased demand resulting from milder weather in the first quarter of 2016 as compared to the same period in 2015. Total heating degree days for the first quarter of 2016 were 18.8% less than the same period last year and 15.5% less than the 30-year average.  KWh sales for our residential and commercial customers decreased during the first quarter of 2016 as compared to the first quarter of 2015 primarily due to the decreased demand resulting from milder weather during the first quarter of 2016. Industrial kWh sales increased 0.8% mainly due to increased usage.

KWh sales for our on-system customers decreased 2.7% during the twelve months ended March 31, 2016, as compared to the same period in 2015, primarily due to decreased demand resulting from the impact of milder weather during the first quarter of 2016 and the fourth quarter of 2015 as compared to the prior year periods. Residential kWh sales, which are more weather sensitive, decreased 7.6% primarily due to the decreased demand resulting from the milder weather. Commercial kWh sales decreased slightly. Industrial KWh sales increased 2.5% mainly due to increased usage.

Revenues and Gross Margin

As shown in the Electric Segment Operating Revenues and Gross Margin table below, electric segment gross margin, defined as electric revenues less fuel and purchased power costs, increased approximately $2.8 million and $14.5 million during the quarter and twelve month period ended March 31, 2016, respectively, as compared to the comparable periods in 2015 mainly due to the July 2015 increase in Missouri electric rates.

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

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Electric Segment Operating Revenues and Gross Margin

	3 months			3 months					12 months			12 months
	ended			ended					ended			ended
Customer Class	2016			2015			% Change(1)		2016			2015			% Change(1)
Residential	$	62.1		$	68.0		(8.7	)%	$	224.6		$	232.3		(3.3	)%
Commercial	37.8			39.3			(3.8	)	170.2			171.5			(0.8	)
Industrial	19.1			19.0			0.5		88.3			85.8			3.0
Wholesale on-system	4.4			3.5			26.8		19.0			20.7			(8.4	)
Other(2)	3.9			3.9			(0.1	)	15.7			15.2			3.3
Total on-system revenues	127.3			133.7			(4.8	)	517.8			525.5			(1.5	)
Off-system wholesale(3)	—			—			—		0.0			0.1			(100.0	)
SPP IM net revenues(3)	3.1			4.7			(34.3	)	13.4			40.3			(66.7	)
Total revenues from KWh sales	130.4			138.4			(5.8	)	531.2			565.9			(6.1	)
Miscellaneous revenues(4)	3.4			3.7			(7.4	)	13.5			14.1			(4.2	)
Total electric operating revenues	$	133.8		$	142.1		(5.8	)	$	544.7		$	580.0		(6.1	)
Water revenues	0.5			0.5			1.1		2.1			2.1			0.6
Total electric segment operating revenues	$	134.3		$	142.6		(5.8	)	$	546.8		$	582.1		(6.1	)
Actual fuel and purchased power expenditures(5)	$	32.5		$	37.9		(14.2	)	$	135.6		$	148.2		(8.5	)
SPP IM net purchases(3)	4.1			6.3			(34.5	)	20.4			55.9			(63.5	)
Net fuel recovery and deferral	1.8			5.2			(65.8	)	5.4			6.2			(12.2	)
SWPA amortization(6)	(0.6		)	(0.7		)	6.9		(2.5		)	(2.5		)	2.7
Unrealized (gain)/loss on derivatives	0.0			0.2			(77.4	)	(0.2		)	0.7			(132.8	)
Total fuel and purchased power expense per income statement	37.8			48.9			(22.7	)	158.7			208.5			(23.9	)
Total Gross Margin	$	96.5		$	93.7		3.1		$	388.1		$	373.6		3.9

(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)  The SPP IM was implemented on March 1, 2014.  As of December 31, 2014, off-system revenues were effectively   replaced by SPP IM activity. When we sell more generation to the market than we purchase, based on the prescribed time increments, the net sale and corresponding net revenue is included as part of electric revenues.

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

(5) When we purchase more generation from the market than we sell, based on the prescribed time increments, the net purchase cost is recorded as a component of fuel and purchased power expense on the financial statements.

(6) Missouri ten year amortization of the $26.6 million payment received from the SWPA in September, 2010, of which $10.0 million of the Missouri portion remains to be amortized as of March 31, 2016.

As previously mentioned, electric margins increased period over period, but revenues for our on-system customers decreased $6.4 million during the first quarter of 2016. Increased customer rates of $7.7 million, primarily due to the July 2015 increase in Missouri electric rates, net of a $1.9 million decrease resulting from a lowering of Missouri base fuel recovery, contributed an estimated $5.8 million to revenues, driving gross margins higher. Improved customer counts increased revenues an estimated $0.7 million. Weather and other volumetric related factors decreased revenues an estimated $10.5 million. A $3.1 million decrease in Missouri non-base fuel recovery revenue, partially offset by a $0.7 million increase in non-Missouri fuel recovery revenue, decreased revenues. Both of these items were offset by a corresponding change in fuel expenses, resulting in little effect on gross margin.

Revenues for our on-system customers decreased $7.6 million for the twelve months ended March 31, 2016, however, gross margin increased $14.5 million. Increased customer rates of $17.8 million, primarily due to the July 2015 increase in Missouri electric rates, net of a $5.2 million decrease resulting from a lowering of Missouri base fuel recovery, contributed an estimated $12.6 million to revenues. Improved customer counts increased revenues an estimated $2.5 million. Weather and other volumetric related factors decreased revenues an estimated $15.0 million. Also negatively impacting revenues was an $6.7 million decrease in Missouri non-base fuel recovery revenue and a $1.0 million decrease in non-Missouri fuel recovery revenue (both of which were offset by a corresponding change in fuel expenses, resulting in little effect on gross margin).

Fuel expense decreases during both the first quarter of 2016 and the twelve months ended March 31, 2016, reflective of the content and timing of the non-Missouri fuel recovery and deferral

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mechanisms and decreased consumable costs, also contributed positively to electric segment gross margin.

In the past, in addition to sales to our own customers, we also sold power to other utilities as available, including (since 2007) through the SPP Energy Imbalance Services (EIS) market. However, on March 1, 2014, the SPP RTO implemented a Day-Ahead Market, or Integrated Marketplace (IM). The majority of the revenues and expenses from these market activities flow through the fuel adjustment 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. See the Electric Segment Operating Revenues and Gross Margin table (SPP IM net purchases) above and “— Markets and Transmission” below.

Operating Expenses — Other Than Fuel and Purchased Power

The table below shows regulated operating expense increases/(decreases) during the first quarter of 2016 and the twelve months ended March 31, 2016 as compared to the same periods in 2015 (in millions):

	Three Months Ended			Twelve Months Ended
	2016 vs. 2015			2016 vs. 2015
Transmission expense	$	(0.2	)	$	0.7
Distribution expense	(0.1		)	(0.3		)
Power operation expense	(1.3		)	(0.4		)
Employee health care expense	0.0			0.6
Employee pension expense	(0.2		)	(0.5		)
General office supplies and expense	1.4			2.1
Administrative and general expense	(0.4		)	(0.3		)
Allowance for uncollectible accounts	(0.1		)	(0.8		)
Other miscellaneous accounts (netted)	0.0			(0.1		)
TOTAL	$	(0.9	)	$	1.0

The table below shows maintenance and repairs expense increases/(decreases) during the first quarter of 2016 and the twelve months ended March 31, 2016 compared to the same periods in 2015 (in millions):

	Three Months Ended			Twelve Months Ended
	2016 vs. 2015			2016 vs. 2015
Transmission and distribution maintenance expense	$	(0.3	)	$	(1.7	)
Maintenance and repairs expense at:
Energy Center	(0.3		)	(1.5		)
Asbury plant	(0.1		)	(0.4		)
SLCC	(0.3		)	2.7		(1)
State Line plant	0.0			(0.2		)
Iatan plant	(0.1		)	0.3
Plum Point plant	1.2			1.3
Riverton plant	(0.1		)	1.2		(2)
Water plant	0.0			(0.2		)
Other miscellaneous accounts (netted)	(0.1		)	0.1
TOTAL	$	(0.1	)	$	1.6

(1)Mainly due to a planned maintenance outage.

(2)Mainly due to a new maintenance contract for the Riverton facility.

In connection with entering into the Merger Agreement, Empire has incurred approximately $4.5 million of merger related expenses as of March 31, 2016.

Depreciation and amortization expense increased approximately $0.3 million (1.8%) and $5.5 million (7.9%) during the quarter and twelve month periods ended March 31, 2016, respectively, primarily due to increased plant in service.

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Other taxes decreased approximately $0.4 million during the quarter ended March 31, 2016. Other taxes increased approximately $1.5 million during the twelve months ended March 31, 2016 due to increased property tax (reflecting our additions to plant in service).

Gas Segment

Gas Operating Revenues and Sales

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

Total Gas Delivered to Customers

	Three Months Ended				Twelve Months Ended
(bcf sales)	2016	2015	% change		2016	2015	% change
Residential	1.11	1.27	(13.0	)%	2.05	2.49	(17.6	)%
Commercial	0.46	0.54	(13.0	)	0.98	1.15	(15.0	)
Industrial	0.02	0.02	(17.1	)	0.03	0.05	(24.0	)
Other(1)	0.02	0.02	2.3		0.03	0.03	(7.5	)
Total retail sales	1.61	1.85	(12.9	)	3.09	3.72	(16.8	)
Transportation sales	1.29	1.46	(11.8	)	4.28	4.82	(11.2	)
Total gas operating sales	2.90	3.31	(12.4	)	7.37	8.54	(13.6	)

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

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

Operating Revenues and Cost of Gas Sold

	Three Months Ended						Twelve Months Ended
($ in millions)	2016		2015		% change		2016		2015		% change
Residential	$	9.8	$	13.0	(24.6	)%	$	23.1	$	29.8	(22.6	)%
Commercial	3.9		5.2		(25.8	)	9.3		12.2		(23.3	)
Industrial	0.1		0.2		(33.4	)	0.3		0.4		(33.2	)
Other(1)	0.1		0.1		(14.7	)	0.3		0.3		(18.3	)
Total retail revenues	$	13.9	$	18.5	(24.9	)	$	33.0	$	42.7	(22.9	)
Other revenues	0.1		0.1		(17.2	)	0.4		0.4		(9.2	)
Transportation revenues	1.1		1.2		(6.3	)	3.6		3.9		(6.3	)
Total gas operating revenues	$	15.1	$	19.8	(23.7	)	$	37.0	$	47.0	(21.4	)
Cost of gas sold	7.5		11.4		(33.8	)	15.6		23.4		(33.2	)
Gas segment gross margins	$	7.6	$	8.4	(10.0	)	$	21.4	$	23.6	(9.7	)

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

Gas retail sales and revenues decreased reflecting decreased demand due to milder temperatures during the first quarter of 2016 as compared to 2015. Heating degree days were 16.0% lower in the first quarter of 2016 as compared to the first quarter of 2015 and 14.9% lower than the 30-year average. As a result, our gas gross margin (defined as gas operating revenues less cost of gas in rates) decreased $0.8 million in the first quarter of 2016 as compared to the same period in 2015.

Gas retail sales and revenues decreased during the twelve months ended March 31, 2016 as compared to the same period in 2015 primarily due to decreased demand from the impacts of milder weather during the 2015-2016 gas heating season (which runs from November to March) as compared to the same period in 2014-2015. Our margin for the twelve months ended March 31, 2016 decreased $2.2 million as compared to the same period in 2015.

We have a PGA clause in place that allows us to recover from our customers, subject to routine regulatory review, the cost of purchased gas supplies, transportation and storage, including costs associated with the use of financial instruments to hedge the purchase price of natural gas. Pursuant to the provisions of the PGA clause, the difference between actual costs incurred and costs recovered through the application of the PGA are reflected as a regulatory asset or regulatory liability until the balance is recovered from or credited to customers. As of March 31, 2016, we had unrecovered purchased gas costs of $0.1 million recorded as a current regulatory liability and $1.4 million recorded as a non-current regulatory liability.

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Operating Revenue Deductions

The table below shows regulated operating expense increases/(decreases) for the applicable periods ended March 31, 2016 as compared to the same periods in 2015.

	Three Months Ended			Twelve Months Ended
(in millions)	2016 vs. 2015			2016 vs. 2015
Customer accounts expense	$	(0.1	)	$	(0.4	)
Administrative and general expense	0.2			0.7
Transmission and distribution operation expense	0.0			0.3
TOTAL	$	0.1		$	0.6

Consolidated Company

Income Taxes

The following table shows our consolidated provision for income taxes (in millions) and our consolidated effective federal and state income tax rates for the applicable periods ended March 31:

	Three Months Ended						Twelve Months Ended
	2016			2015			2016			2015
Consolidated provision for income taxes	$	8.6		$	8.8		$	33.7		$	35.9
Consolidated effective federal and state income tax rates	38.1		%	37.5		%	37.6		%	37.1		%

See Note 12 of “Notes to Consolidated Financial Statements (Unaudited)” for more information and discussion concerning our income tax provision and effective tax rates.

Nonoperating Items

The following table shows the total allowance for funds used during construction (AFUDC) for the applicable periods ended March 31. AFUDC increased during the three months ended March 31, 2016 as compared to the same period in 2015 reflecting construction for the Riverton 12 combined cycle project. AFUDC decreased during the twelve months ended March 31, 2016 as compared to the same period in 2015, reflecting completion of the environmental retrofit project at our Asbury plant in December 2014.

	Three Months Ended				Twelve Months Ended
($ in millions)	2016		2015		2016		2015
Allowance for equity funds used during construction	$	1.7	$	1.0	$	5.6	$	6.2
Allowance for borrowed funds used during construction	1.1		0.5		3.3		3.3
Total AFUDC	$	2.8	$	1.5	$	8.9	$	9.5

Total interest charges on long-term and short-term debt for the periods ended March 31 are shown below. The change in long-term debt interest for 2016 compared to 2015 reflects the issuance on December 1, 2014, of $60.0 million of 4.27% First Mortgage Bonds due 2044 and the issuance of $60.0 million of 3.59% First Mortgage Bonds due 2030 on August 20, 2015. The proceeds from both bond issuances were used to refinance existing short-term indebtedness and for general corporate purposes.

	Interest Charges
	($ in millions)
	3 Months		3 Months				12 Months		12 Months
	Ended		Ended		%		Ended		Ended		%
	2016		2015		Change		2016		2015		Change
Long-term debt interest	$	11.3	$	10.7	5.1	%	$	44.3	$	41.3	7.4	%
Short-term debt interest	0.1		0.1		(14.7	)	0.3		0.2		40.6
Other interest	0.2		0.2		21.4		1.1		1.0		8.7
Total interest charges	$	11.6	$	11.0	5.3		$	45.7	$	42.5	7.6

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RATE MATTERS

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

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

The following table sets forth information regarding electric and water rate increases since January 1, 2013:

Jurisdiction	Date Requested	Annual Increase Granted		Percent Increase Granted		Date Effective
Missouri — Electric	August 29, 2014	$	17,125,000	3.90	%	July 26, 2015
Kansas - Electric	December 5, 2014	$	782,479	4.71	%	June 1, 2015
Arkansas - Electric	February 23, 2015	$	457,000	3.35	%	February 23, 2015
Kansas - Electric	January 22, 2015	$	273,455	1.08	%	February 23, 2015
Arkansas - Electric	December 3, 2013	$	1,366,809	11.34	%	September 26, 2014
Missouri — Electric	July 6, 2012	$	27,500,000	6.78	%	April 1, 2013

On October 16, 2015, we filed a request with the Missouri Public Service Commission (MPSC) for changes in rates for our Missouri electric customers. We are seeking an annual increase in total revenue of approximately $33.4 million, or approximately 7.3%. The most significant factor driving the rate request is the cost associated with the conversion of the Riverton Unit 12 natural gas combustion turbine to combined cycle operation.

We filed our most recent Integrated Resource Plan (IRP) with the MPSC on April 1, 2016. The IRP analysis of future loads and resources is normally conducted once every three years. This IRP reflects the completion of our 2013 Compliance Plan discussed in Note 7 of “Notes to Consolidated Financial Statements (Unaudited)”.

Our other rate cases, as we reported in our Annual Report on Form 10-K for the year ended December 31, 2015, remain unchanged. See Note 3, “Regulatory Matters” in our Annual Report on Form 10-K for the year ended December 31, 2015 for additional information

MARKETS AND TRANSMISSION

Electric Segment

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

As part of the IM, we and other SPP members submit generation offers to sell our power and bids to purchase power into the SPP market, with the SPP serving as a centralized commitment and dispatch of SPP members’ generation resources. The SPP matches offers and bids based upon operating and reliability considerations. The SPP reports that approximately 90%-95% of all next day

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generation needed throughout the SPP territory is being cleared through the IM. We also acquire Transmission Congestion Rights (TCR) through annual and monthly processes in an attempt to mitigate congestion costs associated with the power we purchase from the IM. When we sell more generation to the market than we purchase for a given settlement period, the net sale is included as part of electric revenues. When we purchase more generation from the market than we sell, the net purchase is recorded as a component of fuel and purchased power on our financial statements. The net financial effect of these IM transactions is included in our fuel adjustment mechanisms and therefore has little impact on gross margin.

SPP/Midcontinent Independent System Operator (MISO) Joint Operating Agreement and Plum Point Delivery:  Due to Plum Point’s physical location and interconnection, transmission service from Entergy/MISO is required for delivery. On December 19, 2013, Entergy voluntarily integrated its generation, transmission, and load into the MISO regional transmission organization. Based on the current terms and conditions of MISO membership, Entergy’s participation in MISO has increased transmission delivery costs for our Plum Point power station as well as utilizes our transmission system without compensation.

As a result, we have participated with the SPP members and other impacted utilities in two separate FERC settlement proceedings in an effort to reduce the costs to our customers. On October 13, 2015, SPP members, SPP, MISO and MISO members filed a settlement at the FERC regarding MISO’s unreserved and uncompensated use of the SPP members’ systems. As approved by the FERC, the agreement provides compensation and governance for the continued shared use of the transmission system among MISO, SPP and other impacted utilities. The regional through and out transmission delivery rate (RTOR) dispute regarding Plum Point has proceeded through settlement discussions and a resulting settlement agreement was filed with the FERC on February 25, 2016. The filing continues through the FERC process as of the date of this quarterly report.

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, 2015.

LIQUIDITY AND CAPITAL RESOURCES

Overview.              Our primary sources of liquidity are cash provided by operating activities, short-term borrowings under our commercial paper program (which is supported by our unsecured revolving credit facility) and borrowings from our unsecured revolving credit facility. Historically, we have also successfully raised funds, as needed, from the debt and equity capital markets to fund our liquidity and capital resource needs.

Our issuance of various securities, including equity, long-term and short-term debt, is subject to customary approval or authorization by state and federal regulatory bodies including state public service commissions and the SEC. We believe the cash provided by operating activities, together 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, 2015 for additional information on items that could impact our liquidity and capital resource requirements. The following table provides a summary of our operating, investing and financing activities for the quarters ended March 31:

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Summary of Cash Flows

	Quarter Ended March 31,
(in millions)	2016			2015			Change
Cash provided by/(used in):
Operating activities	$	51.4		$	54.8		$	(3.4	)
Investing activities	(35.8		)	(53.5		)	17.7
Financing activities	(15.7		)	(0.7		)	(15.0		)
Net change in cash and cash equivalents	$	(0.1	)	$	0.6		$	(0.7	)

Cash flow from Operating Activities

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

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

First Quarter 2016 Compared to 2015.  During the first quarter of 2016, our net cash flows provided from operating activities decreased $3.4 million, or 6.2%, from the first quarter of 2015. This change resulted primarily from the following:

·Decrease in net income - $(0.6) million.

·Changes in regulatory amortizations - $(3.5) million.

·Working capital changes for accounts receivable, accounts payable and other current assets and liabilities - $(4.5) million.

·Changes in pension and OPEB related amortizations — $1.5 million.

·Changes to deferred taxes, primarily related to tax depreciation and recognition of tax net operating losses - $1.4 million.

·Adjustments related to stock compensation valuations - $1.5 million.

·Regulatory fuel adjustment accruals - $1.1 million.

Capital Requirements and Investing Activities

Our net cash flows used in investing activities decreased $17.7 million during the first quarter of 2016 as compared to the first quarter of 2015, primarily due to a decrease in capital expenditures for the Riverton 12 combined cycle construction period over period.

Our capital expenditures incurred totaled approximately $34.5 million during the first quarter of 2016 compared to $53.6 million in the first quarter of 2015.

A breakdown of the capital expenditures for the quarters ended March 31, 2016 and 2015 is as follows:

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	Capital Expenditures
(in millions)	2016		2015
Distribution and transmission system additions	$	15.9	$	15.8
New Generation - Riverton 12 combined cycle	9.0		30.6
Additions and replacements — electric plant	3.4		3.8
Gas segment additions and replacements	0.8		0.6
Transportation	3.6		0.2
Other (including retirements and salvage - net) (1)	1.4		2.0
Subtotal	34.1		53.0
Non-regulated capital expenditures (primarily fiber optics)	0.4		0.6
Subtotal capital expenditures incurred (2)	34.5		53.6
Adjusted for capital expenditures payable (3)	1.3		(0.1		)
Total cash outlay	$	35.8	$	53.5

(1)  Other includes equity AFUDC of $(1.7) for 2016 and $(1.0) for 2015.

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

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

100.0% of our cash requirements for capital expenditures during the first quarter of 2016 were satisfied from internally generated funds (funds provided by operating activities less dividends paid).

We estimate that internally generated funds will provide 100.0% of the funds required for the remainder of our budgeted 2016 capital expenditures. If additional financing is needed, we intend to utilize short-term debt and a combination of debt and equity securities.

Financing Activities

First quarter 2016 compared to 2015.

Our net cash flows used in financing activities was $15.7 million in the first quarter of 2016, a decrease of $15.0 million as compared to the first quarter of 2015, primarily due to the following:

·Net short-term repayments of $6.0 million during the first quarter of 2016 as compared to net short-term borrowings $9.0 million during the first quarter of 2015.

Shelf Registration

We have a $200.0 million shelf registration statement with the SEC, effective December 13, 2013, covering our common stock, unsecured debt securities, preference stock, and first mortgage bonds. As of March 31, 2016, $200.0 million remains available for issuance under this shelf registration statement. However, as a result of our regulatory approvals, we may only issue up to $150.0 million of such securities in the form of first mortgage bonds, of which $30.0 million remains available after the issuance of $60.0 million in first mortgage bonds on August 20, 2015 and $60 million on December 1, 2014. Any proceeds from offerings made pursuant to this shelf would be used to fund capital expenditures, refinance existing debt or general corporate needs during the effective period through December 2016.

Credit Agreements

We have in place a $200 million 5-year Credit Agreement which expires in October 2019. This agreement may be used for working capital, commercial paper back-up and general corporate purposes. The credit facility includes a $20 million swingline loan sublimit, a $20 million sublimit for letters of credit issuance and, subject to bank approval, a $75 million accordion feature and two one-year extensions of the credit facility’s maturity date. See Note 6 of “Notes to Consolidated Financial Statements” under Item 8 for additional information regarding this agreement and our unsecured line of credit.

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EDE Mortgage Indenture

Substantially all of the property, plant and equipment of The Empire District Electric Company (but not its subsidiaries) is subject to the lien of the EDE Mortgage. Restrictions in the EDE mortgage bond indenture could affect our liquidity. The principal amount of all series of first mortgage bonds outstanding at any one time under the Indenture of Mortgage and Deed of Trust of The Empire District Electric Company (EDE Mortgage) is limited by terms of the mortgage to $1.0 billion. Based on the $1.0 billion limit, and our current level of outstanding first mortgage bonds, we are limited to the issuance of $297.0 million of new first mortgage bonds. The EDE Mortgage contains a requirement that for new first mortgage bonds to be issued, our net earnings (as defined in the EDE Mortgage) for any twelve consecutive months within the fifteen months preceding issuance must be two times the annual interest requirements (as defined in the EDE Mortgage) on all first mortgage bonds then outstanding and on the prospective issue of new first mortgage bonds. In addition to the interest coverage requirement, the EDE Mortgage provides that new bonds must be issued against, among other things, retired bonds or 60% of net property additions. The annual interest coverage requirement and retired bonds or 60% of net property additions tests would permit the issuance of more than $297.0 million of new first mortgage bonds; however, as discussed above, we are otherwise limited to the issuance of no more than $297.0 million of new first mortgage bonds.  As of March 31, 2016, we are in compliance with all restrictive covenants of the EDE Mortgage.

EDG Mortgage Indenture

The principal amount of all series of first mortgage bonds outstanding at any one time under the Indenture of Mortgage and Deed of Trust of The Empire District Gas Company (EDG Mortgage) is limited by terms of the mortgage to $300.0 million. Substantially all of the property, plant and equipment of The Empire District Gas Company is subject to the lien of the EDG Mortgage. The EDG Mortgage contains a requirement that for new first mortgage bonds to be issued, the amount of such new first mortgage bonds shall not exceed 75% of the cost of property additions acquired after the date of the Missouri Gas acquisition. The mortgage also contains a limitation on the issuance by EDG of debt (including first mortgage bonds, but excluding short-term debt incurred in the ordinary course under working capital facilities) unless, after giving effect to such issuance, EDG’s ratio of EBITDA (defined as net income plus interest, taxes, depreciation, amortization and certain other non-cash charges) to interest charges for the most recent four fiscal quarters is at least 2.0 to 1.0. As of March 31, 2016, this test would allow us to issue approximately $12.3 million principal amount of new first mortgage bonds at an assumed interest rate of 5.5%. As of March 31, 2016, we are in compliance with all restrictive covenants of the EDG Mortgage.

Credit Ratings

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

	Moody’s	Standard & Poor’s
Corporate Credit Rating	Baa1	BBB
EDE First Mortgage Bonds	A2	A-
Senior Notes	Baa1	BBB
Commercial Paper	P-2	A-2
Outlook	Stable	Negative

On March 4, 2016, Moody’s reaffirmed our credit ratings and outlook. On December 15, 2015, Standard & Poor’s reaffirmed our credit ratings and revised our outlook to developing from stable in light of the December 13, 2015 announcement regarding our exploration of strategic alternatives. On February 10, 2016, Standard & Poor’s reaffirmed our credit ratings and revised our outlook to negative from developing in light of the February 9, 2016 announcement regarding the proposed merger. On April 29, 2016, Standard & Poor’s reaffirmed our credit ratings and outlook

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

40

has its own methodology for assigning ratings, and, accordingly, each rating should be considered independently of all other ratings.

CONTRACTUAL OBLIGATIONS

Our contractual obligations have not materially changed at March 31, 2016, compared to December 31, 2015. See “Contractual Obligations” in our Annual Report on Form 10-K for the year ended December 31, 2015.

DIVIDENDS

Holders of our common stock are entitled to dividends if declared by the Board of Directors, out of funds legally available therefore, subject to the prior rights of holders of any outstanding cumulative preferred stock and preference stock. Payment of dividends is determined by our Board of Directors after considering all relevant factors, including the amount of our retained earnings (which is essentially our accumulated net income less dividend payouts). A reduction of our dividend per share, partially or in whole, could have an adverse effect on our common stock price.

On April 28, 2016, the Board of Directors declared a quarterly dividend of $0.26 per share on common stock payable on June 15, 2016 to holders of record as of June 1, 2016.

OFF-BALANCE SHEET ARRANGEMENTS

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

CRITICAL ACCOUNTING POLICIES

See “Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report on Form 10-K for the year ended December 31, 2014 for a discussion of additional critical accounting policies. There were no changes in these policies in the quarter ended March 31, 2016

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 can be extremely volatile. This volatility impacts our cost of power purchased and our participation in energy trades. In addition, congestion on the transmission system can limit our ability to make purchases from (or sell into) the wholesale markets.

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

41

Commodity Price Risk.

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

We satisfied 65.0% of our 2015 generation fuel supply need through coal. Approximately 97% of our 2015 coal supply was Western coal. We have contracts and binding proposals to supply a portion of the fuel for our coal plants through 2017. With these contracts and existing inventory, we have secured approximately 100% of our anticipated fuel requirements for 2016, 46% for 2017 and 23% for 2018 for our Asbury coal plant. In order to manage our exposure to fuel prices, future coal supplies will be acquired using a combination of short-term and long-term contracts.

We are exposed to changes in market prices for natural gas we must purchase to run our combustion turbine generators. Our natural gas procurement program is designed to manage our costs to avoid volatile natural gas prices. We enter into physical forward and financial derivative contracts with counterparties relating to our future natural gas requirements that lock in prices (with respect to predetermined percentages of our expected future natural gas needs) in an attempt to lessen the volatility in our fuel expenditures and improve predictability. As of March 31, 2016, 56%, or 6.5 million Dths, of our anticipated volume of natural gas usage for our electric operations for the remainder of 2016 is hedged.

Based on our expected natural gas purchases for our electric operations for the next twelve months, if average natural gas prices should increase 10% more than the price at March 31, 2016, our natural gas expenditures would increase by approximately $1.1 million based on our March 31, 2016 total hedged positions for the next twelve months. However, such an increase would be probable of recovery through fuel adjustment mechanisms in all of our jurisdictions, which significantly reduces the impact of fluctuating fuel costs.

We attempt to mitigate a portion of our natural gas price risk associated with our gas segment using physical forward purchase agreements, storage and derivative contracts. As of March 31, 2016, we have 1.3 million Dths in storage on the three pipelines that serve our customers. This represents 61% of our storage capacity. We have an additional 0.5 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 March 31, 2016 and December 31, 2015 (in millions).

	March 31, 2016		December 31, 2015
Margin deposit assets	$	10.3	$	11.2

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 smaller, less diverse group of counterparties and transactions may involve large notional volumes and potentially volatile commodity prices. Below is a table showing our net credit

42

exposure at March 31, 2016, 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	$	5.1
Net unrealized mark-to-market losses for financial natural gas contracts	9.0
Net credit exposure	$	14.1

The $9.0 million net unrealized mark-to-market loss for financial natural gas contracts is comprised entirely of $9.0 million that our counterparties are exposed to Empire for unrealized losses. We are holding no collateral from any counterparty since we are below the $10.0 million mark-to-market collateral threshold in our agreements. As noted above, as of March 31, 2016, we have $10.3 million on deposit for NYMEX contract exposure to Empire, of which $10.0 million represents our collateral requirement. If NYMEX gas prices decreased 25% from their March 31, 2016 levels, our collateral requirement would increase $7.9 million. If these prices increased 25%, our collateral requirement would decrease $8.6 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 2016 than in 2015, our interest expense would increase, and income before taxes would decrease by less than $1.0 million. This amount has been determined by considering the impact of the hypothetical interest rates on our highest month-end commercial paper balance for 2015. These analyses do not consider the effects of the reduced level of overall economic activity that could exist in such an environment. In the event of a significant change in interest rates, management would likely take actions to further mitigate its exposure to the change. However, due to the uncertainty of the specific actions that would be taken and their possible effects, the sensitivity analysis assumes no changes in our financial structure.

Item 4.   Controls and Procedures

As of the end of the period covered by this report, an evaluation was carried out, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as such term is defined in Rule 13a-15(e) of the Securities Exchange Act of 1934). Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of March 31, 2016.

There have been no changes in our internal control over financial reporting that occurred during the first quarter of 2016 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

43

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, 2015.

Item 5.  Other Information.

For the twelve months ended March 31, 2016, our ratio of earnings to fixed charges was 2.61x.  See Exhibit (12) hereto.

Item 6.  Exhibits.

(a)Exhibits.

(2)(a) Agreement and Plan of Merger, dated as of February 9, 2016, by and among The Empire District Electric Company, Liberty Utilities (Central) Co. and Liberty Sub Corp. (Incorporated by reference to Exhibit 2.1 to Current Report on Form 8-K dated February 9, 2016 and filed February 9, 2016, File No. 1-3368).

(2)(b) Amended and Restated By-Laws of The Empire District Electric Company, effective February 9, 2016 (Incorporated by reference to Exhibit 3.1 to Current Report on Form 8-K dated February 9, 2016 and filed February 9, 2016,  File No. 1-3368).

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

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

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

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

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

(101) The following financial information from The Empire District Electric Company’s Quarterly Report on Form 10-Q for the period ended March 31, 2016, filed with the SEC on May 6, 2016, formatted in Extensible Business Reporting Language (XBRL): (i) the Consolidated Statements of Income for the three and twelve month periods ended March 31, 2016 and 2015, (ii) the Consolidated Balance Sheets at March 31, 2016 and December 31, 2015, (iii) the Consolidated Statements of Cash Flows for the three-month periods ended March 31, 2016 and 2015, 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.

44

**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.

45

SIGNATURES

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

	THE EMPIRE DISTRICT ELECTRIC COMPANY
	Registrant
	By	/s/ Laurie A. Delano
		Laurie A. Delano
		Vice President — Finance and Chief Financial Officer
	By	/s/ Robert W. Sager
		Robert W. Sager
		Controller, Assistant Secretary and Assistant Treasurer
May 6, 2016

46

EX-12

EXHIBIT (12)

COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES

	Twelve
	Months Ended
	March 31, 2016
Income before provision for income taxes and fixed charges (Note A)	$	145,317,596
Fixed charges:
Interest on long-term debt	$	44,348,486
Interest on short-term debt	254,778
Other interest	1,082,630
Rental expense representative of an interest factor (Note B)	9,980,766
Total fixed charges	$	55,666,660
Ratio of earnings to fixed charges	2.61		x

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

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

EX-31.(A)

Exhibit (31)(a)

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

PURSUANT TO SECTION 302 OF THE

SARBANES-OXLEY ACT OF 2002

I, Bradley P. Beecher, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date: May 6, 2016
By:	/s/ Bradley P. Beecher
	Name:	Bradley P. Beecher
	Title:	President and Chief Executive Officer

EX-31.(B)

Exhibit (31)(b)

CERTIFICATION OF CHIEF FINANCIAL OFFICER

PURSUANT TO SECTION 302 OF THE

SARBANES-OXLEY ACT OF 2002

I, Laurie A. Delano, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date: May 6, 2016
By:	/s/ Laurie A. Delano
	Name:	Laurie A. Delano
	Title:	Vice President - Finance and Chief Financial Officer

EX-32.(A)

Exhibit (32)(a)

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

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

In connection with the Quarterly Report of The Empire District Electric Company (the “Company”) on Form 10-Q for the period ending March 31, 2016 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), Bradley P. Beecher, as Chief Executive Officer of the Company, certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

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

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

By	/s/ Bradley P. Beecher
Name:	Bradley P. Beecher
Title:	President and Chief Executive Officer
Date:	May 6, 2016

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

EX-32.(B)

Exhibit (32)(b)

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

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

In connection with the Quarterly Report of The Empire District Electric Company (the “Company”) on Form 10-Q for the period ending March 31, 2016 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), Laurie A. Delano, as Chief Financial Officer of the Company, certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

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

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

By	/s/ Laurie A. Delano
Name:	Laurie A. Delano
Title:	Vice President - Finance and Chief Financial Officer
Date:	May 6, 2016

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

XML

Document and Entity Information - shares	3 Months Ended
	Mar. 31, 2016	Apr. 29, 2016
Document and Entity Information
Entity Registrant Name	EMPIRE DISTRICT ELECTRIC CO
Entity Central Index Key	0000032689
Document Type	10-Q
Document Period End Date	Mar. 31, 2016
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		43,923,742
Document Fiscal Year Focus	2016
Document Fiscal Period Focus	Q1

XML

Consolidated Statements of Income - USD ($) shares in Thousands, $ in Thousands	3 Months Ended		12 Months Ended
	Mar. 31, 2016	Mar. 31, 2015	Mar. 31, 2016	Mar. 31, 2015
Operating revenues:
Electric	$ 134,363	$ 142,641	$ 546,808	$ 582,043
Gas	15,113	19,818	36,997	47,051
Other	1,839	2,085	8,539	8,107
Total operating revenues	151,315	164,544	592,344	637,201
Operating revenue deductions:
Fuel and purchased power	37,840	48,977	158,723	208,477
Cost of natural gas sold and transported	7,561	11,423	15,639	23,403
Regulated operating expenses	27,845	28,551	112,845	111,371
Other operating expenses	961	805	3,466	3,076
Maintenance and repairs	10,218	10,267	48,474	46,784
Merger related expenses	4,248		4,499
Depreciation and amortization	20,403	20,020	80,933	75,264
Provision for income taxes	8,675	8,884	34,592	36,108
Other taxes	10,321	10,904	38,595	37,493
Total operating revenue deductions	128,072	139,831	497,766	541,976
Operating income	23,243	24,713	94,578	95,225
Other income and (deductions):
Allowance for equity funds used during construction	1,704	978	5,577	6,147
Interest income	9	11	144	20
Benefit for other income taxes	36	113	910	237
Other - non-operating expense, net	(408)	(698)	(2,887)	(1,655)
Total other income	1,341	404	3,744	4,749
Interest charges:
Long-term debt	11,298	10,751	44,348	41,283
Short-term debt	62	73	255	181
Allowance for borrowed funds used during construction	(1,053)	(564)	(3,333)	(3,320)
Other	268	220	1,083	995
Total interest charges	10,575	10,480	42,353	39,139
Net income	$ 14,009	$ 14,637	$ 55,969	$ 60,835
Weighted average number of common shares outstanding - basic (in shares)	43,882	43,531	43,758	43,395
Weighted average number of common shares outstanding - diluted (in shares)	43,937	43,612	43,777	43,460
Total earnings per weighted average share of common stock - basic and diluted (in dollars per share)	$ 0.32	$ 0.34	$ 1.28	$ 1.40
Dividends declared per share of common stock (in dollars per share)	$ 0.26	$ 0.26	$ 1.04	$ 1.03

XML

Consolidated Balance Sheets - USD ($) $ in Thousands	Mar. 31, 2016	Dec. 31, 2015
Plant and property, at original cost:
Electric	$ 2,492,315	$ 2,473,927
Gas	84,586	83,402
Other	44,739	44,263
Construction work in progress	194,568	183,689
Total plant and property, Gross	2,816,208	2,785,281
Accumulated depreciation and amortization	779,891	764,895
Total plant and property, Net	2,036,317	2,020,386
Current assets:
Cash and cash equivalents	1,672	1,753
Restricted cash	4,727	4,726
Accounts receivable - trade, net of allowance $820 and $623, respectively	43,357	40,162
Accrued unbilled revenues	15,661	20,653
Accounts receivable - other	22,283	28,320
Fuel, materials and supplies	58,349	60,950
Prepaid expenses and other	8,070	8,835
Unrealized gain in fair value of derivative contracts	608	1,295
Regulatory assets	7,145	7,052
Total current assets	161,872	173,746
Noncurrent assets and deferred charges:
Regulatory assets	209,934	209,708
Goodwill	39,492	39,492
Unrealized gain in fair value of derivative contracts		16
Other	3,311	3,297
Total noncurrent assets and deferred charges	252,737	252,513
Total Assets	2,450,926	2,446,645
Capitalization and liabilities
Common stock, $1 par value, 43,911,310 and 43,820,726 shares issued and outstanding, respectively	43,911	43,821
Capital in excess of par value	660,364	657,466
Retained earnings	104,039	101,443
Total common stockholders' equity	808,314	802,730
Long-term debt (net of current portion):
Obligations under capital lease	3,500	3,580
First mortgage bonds and secured debt	724,996	724,838
Unsecured debt	100,949	100,935
Total long-term debt	829,445	829,353
Total long-term debt and common stockholders' equity	1,637,759	1,632,083
Current liabilities:
Accounts payable and accrued liabilities	43,477	66,946
Current maturities of long-term debt	25,267	25,246
Short-term debt	19,000	25,000
Regulatory liabilities	10,154	8,615
Customer deposits	14,793	14,623
Interest accrued	14,933	7,348
Unrealized loss in fair value of derivative contracts	4,743	4,472
Taxes accrued	9,076	2,832
Other current liabilities	297	323
Total current liabilities	$ 141,740	$ 155,405
Commitments and contingencies (Note 7)
Noncurrent liabilities and deferred credits:
Regulatory liabilities	$ 134,401	$ 132,457
Deferred income taxes	405,250	396,542
Unamortized investment tax credits	18,452	18,487
Pension and other postretirement benefit obligations	83,394	82,144
Unrealized loss in fair value of derivative contracts	3,873	3,696
Other	26,057	25,831
Total noncurrent liabilities	671,427	659,157
Total Capitalization and Liabilities	$ 2,450,926	$ 2,446,645

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Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	Mar. 31, 2016	Dec. 31, 2015
Consolidated Balance Sheets
Accounts receivable - trade, allowance (in dollars)	$ 820	$ 623
Common stock, par value (in dollars per share)	$ 1	$ 1
Common stock, shares issued	43,911,310	43,820,726
Common stock, shares outstanding	43,911,310	43,820,726

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Consolidated Statements of Cash Flows - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Operating activities:
Net income	$ 14,009	$ 14,637
Adjustments to reconcile net income to cash flows from operating activities:
Depreciation and amortization including regulatory items	19,967	23,056
Pension and other postretirement benefit costs, net of contributions	3,164	1,704
Deferred income taxes and unamortized investment tax credit, net	8,640	7,203
Allowance for equity funds used during construction	(1,704)	(978)
Stock compensation expense	2,107	651
Non-cash (gain)/loss on derivatives	909	772
Other	103
Cash flows impacted by changes in:
Accounts receivable and accrued unbilled revenues	6,843	12,475
Fuel, materials and supplies	2,601	1,632
Prepaid expenses, other current assets and deferred charges	(2,241)	2,984
Accounts payable and accrued liabilities	(22,969)	(28,343)
Asset retirement obligations	(40)
Interest, taxes accrued and customer deposits	13,999	15,159
Other liabilities and other deferred credits	5,987	3,800
Net cash provided by operating activities	51,375	54,752
Investing activities:
Capital expenditures - regulated	(35,359)	(52,954)
Capital expenditures and other investments - non-regulated	(417)	(520)
Restricted cash	1
Net cash used in investing activities	(35,775)	(53,474)
Financing activities:
Proceeds from issuance of common stock, net of issuance costs	1,809	1,664
Net short-term borrowings	(6,000)	9,000
Dividends	(11,413)	(11,318)
Other	(77)	(68)
Net cash used in financing activities	(15,681)	(722)
Net increase / (decrease) in cash and cash equivalents	(81)	556
Cash and cash equivalents at beginning of period	1,753	2,105
Cash and cash equivalents at end of period	$ 1,672	$ 2,661

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Summary of Significant Accounting Policies

3 Months Ended

Mar. 31, 2016

Summary of Significant Accounting Policies

Summary of Significant Accounting Policies

Note 1 - Summary of Significant Accounting Policies

We operate our businesses as three segments:  electric, gas and other. The Empire District Electric Company (EDE), a Kansas corporation organized in 1909, is an operating public utility engaged in the generation, purchase, transmission, distribution and sale of electricity in parts of Missouri, Kansas, Oklahoma and Arkansas. As part of our electric segment, we also provide water service to three towns in Missouri. The Empire District Gas Company (EDG) is our wholly-owned subsidiary which provides natural gas distribution to 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, 2015.

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, 2015.

On February 9, 2016, Empire entered into an Agreement and Plan of Merger (the Merger Agreement) with Liberty Utilities (Central) Co., a Delaware corporation (Liberty Central), and Liberty Sub Corp., a Kansas corporation (Merger Sub), providing for the merger of Merger Sub with and into Empire, with Empire surviving the Merger as a wholly-owned subsidiary of Liberty Central (the Merger). See Note 13 for further information.

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Recently Issued and Proposed Accounting Standards

3 Months Ended

Mar. 31, 2016

Recently Issued and Proposed Accounting Standards

Recently Issued and Proposed Accounting Standards

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. In July 2015, the FASB approved a one year delay in the standard’s effective date. The new standard is now effective for interim and annual reporting periods beginning after December 15, 2017. We are evaluating the impact of the adoption of this standard.

Presentation of debt issuance costs:  In April 2015, the FASB issued revised guidance addressing the presentation requirements for debt issuance costs. Under the revised guidance, all costs incurred to issue debt are to be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability. The revised guidance is effective for interim and annual reporting periods beginning after December 15, 2015. The application of this standard resulted in $8.5 million in unamortized debt issuance costs being reclassified from deferred charges to long-term debt on the March 31, 2016 Consolidated Balance Sheet and $8.7 million in unamortized debt issuance costs being reclassified from deferred charges to long-term debt on the December 31, 2015 Consolidated Balance Sheet for comparative purposes.

Recognition and measurement of financial assets and financial liabilities:  In January 2016, the FASB issued revised guidance addressing the recognition, measurement, presentation and disclosure of financial instruments.  Under the revised guidance all equity investments (except those accounted for under the equity method of accounting or those that result in consolidation of the investee) are to be measured at fair value with the changes in fair value recognized in net income.  The amended guidance also addresses the impairment assessment of some equity investments, as well as disclosure requirements. The revised guidance is effective for interim and annual periods beginning after December 15, 2017.  The application of this standard is not expected to have a material impact on our results of operations, financial position or liquidity.

Leases:  In February 2016, the FASB issued new guidance on accounting for leases.  Under the new guidance a lessee will be required to recognize the assets and liabilities arising from leases on the balance sheet.  The new guidance also addresses the income statement treatment for leases.  Under the new guidance leases will be classified as either operating or financing based on criteria that are similar to the old guidance.  Lease expense will be recognized on a straight line basis for operating leases while expense for capital leases will be similar to the finance pattern utilized today.  The new guidance is effective for interim and annual periods beginning after December 15, 2018, with early adoption permitted.  We are evaluating the impact of the adoption of this standard.

Stock Compensation:  In March 2016 the FASB issued revised guidance on stock compensation.  The updated guidance is intended to simplify some aspects of the accounting for stock compensation such as the income tax impact, classification of awards as either equity or liabilities, and cash flow classification. This guidance will be effective for 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, 2015 for further information regarding recently issued and proposed accounting standards.

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Regulatory Matters

3 Months Ended

Mar. 31, 2016

Regulatory Matters

Regulatory Matters

Note 3— Regulatory Matters

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

Regulatory Assets and Liabilities

	March 31, 2016			December 31, 2015
Regulatory Assets:
Current:
Under recovered fuel costs	$	89		$	196
Current portion of long-term regulatory assets	7,056			6,856
Regulatory assets, current	7,145			7,052
Long-term:
Pension and other postretirement benefits(1)	106,237			108,273
Income taxes	48,597			48,613
Deferred construction accounting costs(2)	14,886			14,977
Unamortized loss on reacquired debt	9,563			9,731
Unsettled derivative losses — electric segment	7,785			7,775
System reliability — vegetation management	3,346			3,604
Storm costs	3,389			3,531
Asset retirement obligation	8,644			7,722
Customer programs	6,112			5,942
Missouri solar initiative(3)	6,170			3,504
Current portion of long-term regulatory assets	(7,056		)	(6,856		)
Other	2,261			2,892
Regulatory assets, long-term	209,934			209,708
Total Regulatory Assets	$	217,079		$	216,760

	March 31, 2016			December 31, 2015
Regulatory Liabilities:
Current:
Over recovered fuel costs	$	6,789		$	5,280
Current portion of long-term regulatory liabilities	3,365			3,335
Regulatory liabilities, current	10,154			8,615
Long-term:
Costs of removal(4)	95,673			94,193
SWPA payment for Ozark Beach lost generation	13,580			14,213
Income taxes	11,194			11,244
Deferred construction accounting costs — fuel(5)	7,651			7,690
Unamortized gain on interest rate derivative	2,989			3,031
Pension and other postretirement benefits	1,698			1,745
Over recovered fuel costs	3,168			2,300
System reliability — vegetation management	1,320			1,320
Current portion of long-term regulatory liabilities	(3,365		)	(3,335		)
Other	493			56
Regulatory liabilities, long-term	134,401			132,457
Total Regulatory Liabilities	$	144,555		$	141,072

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

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

(3)  Resulting from the Missouri Clean Energy Initiative and consists of approximately 467 solar rebate applications processed and internal costs as of March 31, 2016 (compared to 262 as of December 31, 2015), resulting in solar rebate-related costs totaling approximately $6.2 million.

(4)  As part of our depreciation rates, we accrue the estimated cost of dismantling and removing plant from service upon retirement. The accrued cost of removal, upon retirement, is reclassified from accumulated depreciation to a regulatory liability. These reclassified amounts are reflected here. See the depreciation discussion under Note 1 and Note 2 Property, Plant and Equipment in our Annual Report on Form 10-K for the fiscal year ended December 31, 2015 for more detail.

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

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Risk Management and Derivative Financial Instruments

3 Months Ended

Mar. 31, 2016

Risk Management and Derivative Financial Instruments

Risk Management and Derivative Financial Instruments

Note 4— Risk Management and Derivative Financial Instruments

We engage in hedging activities in an effort to minimize our risk from the volatility of natural gas prices and power cost risk associated with exposure to congestion costs. We enter into both physical and financial contracts with counterparties relating to our future natural gas requirements that lock in prices (with respect to a range of predetermined percentages of our expected future natural gas needs) in an attempt to lessen the volatility in our fuel expenditures and gain predictability.

We began acquiring Transmission Congestion Rights (TCR) in 2013 in an attempt to mitigate the cost of power we purchase from the Southwest Power Pool (SPP) Integrated Marketplace (IM) due to congestion exposure. TCRs entitle the holder to a stream of revenues (or charges) based on the day-ahead congestion on the transmission path. TCRs can be purchased or self-converted using rights allocated based on prior investments made in the transmission system. We recognize that if risk is not timely and adequately balanced or if counterparties fail to perform contractual obligations, actual results could differ materially from intended results.

All derivative instruments are recognized at fair value on the balance sheet. The unrealized losses or gains from derivatives used to hedge our fuel and purchased power costs in our electric segment are recorded in regulatory assets or liabilities. All gains and losses from derivatives related to the gas segment are also recorded in regulatory assets or liabilities. This is in accordance with the Accounting Standards Codification (ASC) guidance on regulated operations, given that those gains or losses are probable of refund or recovery, respectively, through our fuel adjustment mechanisms.

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

As of March 31, 2016 and December 31, 2015, we have recorded the following assets and liabilities representing the fair value of derivative financial instruments, (in thousands):

		March 31,		December 31,
ASSET DERIVATIVES		2016		2015
Hedging instruments	Balance Sheet Classification	Fair Value		Fair Value
Natural gas contracts, gas segment	Current assets	$	18	$	2
	Non-current assets and deferred charges — other	—		16
Natural gas contracts, electric segment	Current assets	—		—
	Non-current assets and deferred charges — other	—		—
Transmission congestion rights, electric segment	Current assets	590		1,293
Total derivatives assets		$	608	$	1,311

		March 31,		December 31,
LIABILITY DERIVATIVES		2016		2015
Hedging instruments	Balance Sheet Classification	Fair Value		Fair Value
Natural gas contracts, gas segment	Current liabilities	$	14	$	282
	Non-current liabilities and deferred credits	51		66
Natural gas contracts, electric segment	Current liabilities	4,729		4,190
	Non-current liabilities and deferred credits	3,822		3,630
Total derivatives liabilities		$	8,616	$	8,168

Electric Segment

At March 31, 2016, approximately $4.7 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 March 31, (in thousands):

Non-Designated Hedging Instruments  — Due to Regulatory Accounting Electric Segment	Balance Sheet  Classification of Gain /  (Loss) on Derivative	Amount of Gain / (Loss) Recognized on Balance  Sheet
		Three Months Ended						Twelve Months Ended
		2016			2015			2016			2015
Commodity contracts	Regulatory (assets)/liabilities	$	(1,709	)	$	(2,540	)	$	(6,022	)	$	(11,077	)
Transmission congestion rights	Regulatory (assets)/liabilities	122			1,105			3,987			13,434
Total Electric Segment		$	(1,587	)	$	(1,435	)	$	(2,035	)	$	2,357

Non-Designated Hedging Instruments  — Due to Regulatory Accounting Electric Segment	Statement of Income  Classification of Gain /  (Loss) on Derivative	Amount of Gain / (Loss) Recognized in Income  on Derivative
		Three Months Ended						Twelve Months Ended
		2016			2015			2016			2015
Commodity contracts	Fuel and purchased power expense	$	(1,698	)	$	(1,421	)	$	(8,392	)	$	(3,834	)
Transmission congestion rights	Fuel and purchased power expense	796			3,438			4,826			13,743
Total Electric Segment		$	(902	)	$	2,017		$	(3,566	)	$	9,909

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

As of March 31, 2016, the following volumes and percentage of our anticipated volume of natural gas usage for our electric operations for the remainder of 2016 and for the next four years are shown below at the following average prices per Dekatherm (Dth). We utilize the following procurement guidelines for our electric segment, allowing the flexibility to hedge up to 100% of the current year’s and 80% of any future year’s expected requirements while being cognizant of volume risk. The 80% guideline is an annual target and volumes up to 100% can be hedged in any given month. For years beyond year four, additional factors of long term uncertainty (including with respect to required volumes and counterparty credit) are also considered.

		Dth Hedged				Procurement
Year	% Hedged	Physical	Financial	Average Price		Guidelines
Remainder 2016	56%	2,676,000	3,860,000	$	3.54	Up to 100%
2017	41%	782,900	5,210,000	$	3.35	60%
2018	20%	565,000	2,460,000	$	3.33	40%
2019	10%	—	1,460,000	$	2.96	20%
2020	—	—	—	—		10%

At March 31, 2016, the following transmission congestion rights (TCR) have been obtained to hedge congestion risk in the SPP IM (dollars in thousands):

Year	Monthly MWH  Hedged	$ Value
2016	1,430	$	590

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 March 31, 2016, we had 1.3 million Dths in storage on the three pipelines that serve our customers. This represents 61% 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 and illustrates our hedged position as of March 31, 2016 (Dth in thousands).

Season	Target % Hedged by September 1	Dth Hedged — Financial	Dth Hedged — Physical	Dth in Storage	Actual % Hedged
Nov. 2016 - Mar. 2017	50%	200,000	—	1,252,281	47%
Nov. 2017 - Mar. 2018	Up to 50%	280,000	—	—	9%
Nov. 2018 - Mar. 2019	Up to 20%	—	—	—	—

A Purchased Gas Adjustment (PGA) clause is included in our rates for our gas segment operations. Therefore, we mark to market any unrealized gains or losses and any realized gains or losses relating to financial derivative contracts to a regulatory asset or regulatory liability account on our balance sheet.

The following table sets forth “mark-to-market” pre-tax gains / (losses) from derivatives not designated as hedging instruments for the gas segment for each of the periods ended March 31 (in thousands).

		Amount of Gain / (Loss)
Non-Designated Hedging	Balance Sheet	Recognized on Balance Sheet
Instruments Due to Regulatory	Classification of Gain or	Three Months Ended						Twelve Months Ended
Accounting — Gas Segment	(Loss) on Derivative	2016			2015			2016			2015
Commodity contracts	Regulatory (assets)/ liabilities	$	(67	)	$	(17	)	$	(497	)	$	(478	)
Total - Gas Segment		$	(67	)	$	(17	)	$	(497	)	$	(478	)

Contingent Features

Certain of our derivative instruments contain provisions that are triggered if we fail to maintain an investment grade credit rating with any relevant credit rating agency. If our debt were to fall below investment grade, the counterparties to the derivative instruments could request increased collateralization on derivative instruments in net liability positions. We had no derivative instruments with the credit-risk-related contingent features in a net liability position on March 31, 2016 and have posted no collateral with counterparties in the normal course of business. Amounts reported as margin deposit assets represent our funds held on deposit for our contracts held with our NYMEX broker and other financial contracts with other counterparties that resulted from us exceeding agreed-upon credit limits established by the counterparties. The following table depicts our margin deposit assets at the dates shown. There were no margin deposit liabilities at these dates.

(in millions)	March 31, 2016		December 31, 2015
Margin deposit assets	$	10.3	$	11.2

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 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 March 31, 2016 and December 31, 2015, 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.

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Fair Value Measurements

3 Months Ended

Mar. 31, 2016

Fair Value Measurements

Fair Value Measurements

Note 5— Fair Value Measurements

The accounting guidance on fair value measurements establishes a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value. These tiers include: (i) Level 1, defined as quoted prices in active markets for identical instruments; (ii) Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and (iii) Level 3, defined as unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions. Our Level 2 fair value measurements consist of both quoted price inputs and inputs that are derived principally from or corroborated by observable market data.

The guidance also requires that the fair value measurements of assets and liabilities reflect the nonperformance risk of counterparties and the reporting entity, as applicable. Therefore, using credit default spreads, we factored the impact of our own credit standing and the credit standing of our counterparties, as well as any potential credit enhancements (e.g. collateral) into the consideration of nonperformance risk for both derivative assets and liabilities. The results of this analysis were not material to the financial statements.

Our TCR positions, which are acquired on the SPP IM, are valued using the most recent monthly auction clearing prices. Our commodity contracts are valued using the market value approach on a recurring basis. The following fair value hierarchy table presents information about our TCR and commodity contracts measured at fair value as of March 31, 2016 and December 31, 2015 (in thousands):

	Fair Value Measurements at Reporting Date Using
Description	Assets/(Liabilities) at Fair Value			Quoted Prices in Active Markets for Identical Assets/(Liabilities) (Level 1)			Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
				March 31, 2016
Derivative assets	$	608		$	18		$	590	$	—
Derivative liabilities	$	(8,616	)	$	(8,616	)	$	—	$	—
				December 31, 2015
Derivative assets	$	1,311		$	18		$	1,293	$	—
Derivative liabilities	$	(8,168	)	$	(8,168	)	$	—	$	—

*The only recurring measurements are derivative related.

Other fair value considerations

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

The carrying amount of our total long-term debt exclusive of capital leases at both March 31, 2016 and December 31, 2015 was $851 million. The fair market value at March 31, 2016 was approximately $856 million as compared to approximately $815 million at December 31, 2015. These estimates were based on a bond pricing model, utilizing inputs classified as Level 2 in the fair value hierarchy, which include the quoted market prices for the same or similar issues or on the current rates offered to us for debt of the same remaining maturities. The estimated fair market value may not represent the actual value that could have been realized as of March 31, 2016 or that will be realizable in the future.

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Financing

3 Months Ended

Mar. 31, 2016

Financing

Financing

Note 6— Financing

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

The credit facility requires our total indebtedness to be less than 65.0% of our total capitalization at the end of each fiscal quarter and a failure to maintain this ratio will result in an event of default under the credit facility and will prohibit us from borrowing funds thereunder. As of March 31, 2016, we were in compliance with this covenant as our ratio of total indebtedness was 52% of our total capitalization. This credit facility is also subject to cross-default if we default on more than $25 million in the aggregate on our other indebtedness. As of March 31, 2016, we were not in default under any of such other indebtedness.

The credit agreement does not legally restrict the use of our cash in the normal course of operations. There were no outstanding borrowings under the agreement at March 31, 2016; however, $19.0 million was used to back up our outstanding commercial paper.

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Commitments and Contingencies

3 Months Ended

Mar. 31, 2016

Commitments and Contingencies

Commitments and Contingencies

Note 7— Commitments and Contingencies

Legal Proceedings

We are a party to various claims and legal proceedings arising out of the normal course of our business. We regularly analyze this information, and provide accruals for any liabilities, in accordance with the guidelines presented in the ASC on accounting for contingencies. In the opinion of management, it is not probable, given the company’s defenses, that the ultimate outcome of these claims and lawsuits will have a material adverse effect upon our financial condition, or results of operations or cash flows.

Proceedings in connection with the pending merger with Liberty Central

On March 24, 2016, a purported shareholder of Empire filed a complaint styled as a class action lawsuit in the District Court for the 3rd Judicial District, in Shawnee County, Kansas. The complaint alleges that Empire’s Board of Directors breached its fiduciary duties in agreeing to the Merger Agreement by, among other things, conducting an inadequate sales process and failing to obtain adequate consideration, having an interest in completing the Merger, and failing to make adequate disclosures in the proxy statement. The complaint seeks various relief, including an injunction against the Merger. The complaint also alleges that Empire, APUC, Liberty Central and Merger Sub aided and abetted such alleged breaches.

The outcome of the lawsuit cannot be predicted with any certainty. A preliminary injunction could delay or jeopardize the completion of the Merger, and an adverse judgment granting permanent injunctive relief could indefinitely enjoin completion of the Merger. All of the defendants believe that the claims asserted against them in the lawsuit are without merit.

Coal, Natural Gas and Transportation Contracts

The following table sets forth our firm physical gas, coal and transportation contracts for the periods indicated as of March 31, 2016 (in millions).

	Firm physical gas and transportation contracts		Coal and coal transportation contracts
April 1, 2016 through December 31, 2016	$	21.8	$	12.2
January 1, 2017 through December 31, 2018	37.4		26.9
January 1, 2019 through December 31, 2020	28.8		10.5
January 1, 2021 and beyond	45.7		—

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. The firm physical gas and transportation commitments are detailed in the table above.

We have coal supply agreements and transportation contracts in place to provide for the delivery of coal to the plants. These contracts are written with Force Majeure clauses that enable us to reduce tonnages or cease shipments under certain circumstances or events. These include mechanical or electrical maintenance items, acts of God, war or insurrection, strikes, weather and other disrupting events. This reduces the risk we have for not taking the minimum requirements of fuel under the contracts. The minimum requirements for our coal and coal transportation contracts as of March 31, 2016, are detailed in the table above.

Purchased Power

We have three purchased power agreements.

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 agreement for the purchase of an additional 50 megawatts of capacity from Plum Point. Commitments under this agreement are approximately $275.1 million through August 31, 2039, the end date of the agreement.

We have a long-term purchased power agreement, which expires in 2028, 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 long-term purchased power agreement, which expires in 2020, with Elk River Windfarm, LLC, owned by IBERDROLA RENEWABLES, Inc., to purchase the energy generated at the 150-megawatt Elk River Windfarm located in Butler County, Kansas. Annual payments are contingent upon output of the facility and can range from zero to a maximum of approximately $16.9 million based on a 20-year average cost.

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

New Construction

In April 2016 we completed the conversion of Riverton Unit 12 from a simple cycle combustion turbine to a combined cycle unit. The conversion included the installation of a heat recovery steam generator (HRSG), steam turbine generator, auxiliary boiler, cooling tower, and other auxiliary equipment. Construction costs through March 31, 2016 were $163.4 million for the project to date, excluding AFUDC. Final cost is estimated to range from $165 million to $175 million, excluding AFUDC. This amount was included in our five-year capital expenditure plan.

See “Environmental Matters” below for more information.

Leases

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

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

The gross amount of assets recorded under capital leases total $5.3 million at March 31, 2016.

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. While we are not in a position to accurately estimate compliance costs for any new requirements, we expect these costs to be material, although recoverable in rates.

Compliance Plan

In order to comply with current and forthcoming environmental regulations, we implemented our compliance plan and strategy (2013 Compliance Plan), which largely followed our Integrated Resource Plan (IRP) filed with the MPSC in mid-2013. On April 1, 2016, we filed our updated IRP, reflecting the completion of our 2013 Compliance Plan. The Mercury Air Toxic Standards (MATS) and the Clean Air Interstate Rule (CAIR), replaced by the Cross State Air Pollution Rule (CSAPR), are the drivers behind our Compliance Plan and its implementation schedule. We anticipate compliance costs associated with the MATS, CAIR and CSAPR regulations to continue to be recoverable in our rates.

The following list summarizes the most significant environmental regulations affecting our operations:

Regulations

Air Emissions - NOx and SO2

CAIR (Clean Air Interstate Rule)

CSAPR (Cross State Air Pollution Rule)

MATS (Mercury Air Toxic Standards)

NAAQS (National Ambient Air Quality Standards)

Greenhouse Gases (GHGs) — CO2

Surface Impoundments

Coal Ash Impoundments:

Asbury Power Plant

Riverton (capped and closed in 2014 as industrial (coal combustion waste) landfill)

Water Discharges

MATS: In June 2015, the U.S. Supreme Court remanded the MATS back to the D.C. Circuit Court, holding that the EPA must consider cost (including cost of compliance) before deciding whether a regulation is appropriate and necessary. The court noted that it will be up to the EPA to decide within the limits of reasonable interpretation how to account for cost. The EPA’s determination claimed that considering cost does not alter the agency’s conclusion that it is appropriate and necessary to regulate coal and oil-fired electric utility steam generating units (EGUs) under the regulation. The U.S. Court of Appeals rejected challenges to the MATS in December 2015 and the MATS remains in effect. The final Technical Corrections Rule was signed March 17, 2016.

Greenhouse Gases: On August 3, 2015, the EPA released the final rule for limiting carbon emissions from existing power plants. The “Clean Power Plan” (CPP) requires a 32% 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. States will choose between two plan types to meet their goals: an emission standards plan which includes source-specific requirements impacting affected power plants or a state measures plan which includes a mixture of measures implemented by the state.

On February 9, 2016, the Supreme Court ordered a stay on the CPP. Twenty-seven states and numerous industry groups have challenged the CPP’s legality in the D.C. Circuit. The stay will remain in effect until the court resolves the legal challenges to the CPP and either the Supreme Court decides not to review the D.C. Circuit’s decision or the Supreme Court issues its own opinion. Other than the cancellation of the initial submittal deadline this September, the EPA has not made any definitive statements regarding whether CPP timelines may change under the stay. The ultimate cost of compliance cannot be determined at this time because of the uncertainties regarding the final outcome of the GHG regulations, including the legal challenges thereto, and the compliance methods yet to be chosen by the jurisdictions in which we operate. In any case, we expect the cost of complying with any such regulations to be recoverable in our rates.

Surface Impoundments: On September 30, 2015, the EPA finalized a revision of the Clean Water Act (CWA) Steam Electric Effluent Limitation Guidelines (ELGs) for coal-fired power plants. The new rule sets technology-based ELGs based on the nature of the pollutants being discharged and the facilities involved. As published, beginning in November 2018, the EPA and states would incorporate the new standards into all wastewater discharge permits, including permits for coal ash impoundments. We do not have sufficient information at this time to estimate additional costs at each facility that will result from the new standards to be in effect no later than December 2023.

Effective October 19, 2015, the EPA established a final rule to regulate the disposal of coal combustion residuals (CCRs) as a non-hazardous solid waste under subtitle D of the Resource Conservation and Recovery Act (RCRA). We expect compliance with both the CCR and ELG rule to result in the need to construct a new landfill and the conversion of existing bottom ash handling from a wet to a dry system at a potential cost of up to $15 million at our Asbury Power Plant. We expect resulting costs to be recoverable in our rates. Final closure of the existing ash impoundment, for which an asset retirement obligation of $5.4 million has been recorded, is anticipated after the new landfill is operational. Separately, an asset retirement obligation of $4.4 million has been recorded for our interest in the coal ash impoundment at the Iatan Generating Station.

On February 1, 2016, a construction permit application was submitted to the Missouri Department of Natural Resources’ Solid Waste Management Program (SWMP) for a new utility waste landfill adjacent to the Asbury plant. The application has been determined to be complete and a technical review by the SWMP is in progress. Approval of the final construction permit for the CCR waste landfill is expected by February 2017.

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 EPA final rule under the CWA Section 316(b) for existing cooling water intake structures became effective on October 14, 2014. An industry coalition has filed an appeal of the rule in the Fifth Circuit and additional court challenges are expected. We expect the regulations to have no future impact at Riverton as the new intake structure design and installed cooling tower, as part of the Unit 12 conversion, meets the regulatory requirement for aquatic life protections. Impacts at Iatan 1 could range from flow velocity reductions or traveling screen modifications for fish handling to installation of a closed cycle cooling tower retrofit.  Iatan Unit 2 and Plum Point Unit 1 are covered by the regulation, but were constructed with cooling towers, the proposed Best Technology Available. We expect them to be unaffected or minimally affected by the final rule.

Renewable Energy

The Clean Energy Initiative (Proposition C) requires Empire and other investor-owned utilities in Missouri to generate or purchase electricity from renewable energy sources, such as solar, wind, biomass and hydro power, or purchase Renewable Energy Credits (RECs), in amounts equal to at least 5% of retail sales in 2014-2017, at least 10% in 2018-2020 and at least 15% by 2021. We are currently in compliance with this regulatory requirement as a result of generation from our Ozark Beach Hydroelectric Project and purchased power agreements previously mentioned with Cloud County Windfarm, LLC and Elk River Windfarm, LLC. Proposition C also requires that 2% of the energy from renewable energy sources must be solar. On May 6, 2015, the MPSC approved tariffs we filed on May 5, 2015 to establish solar rebate payment procedures and revise our net metering tariffs to accommodate the payment of solar rebates. As of March 31, 2016, we had processed 467 solar rebate applications resulting in solar rebate-related costs totaling approximately $6.2 million under the new tariff. We have recorded the $6.2 million as a regulatory asset (See Note 3 — Regulatory Matters). The law provides a number of methods that may be utilized to recover the associated expenses. We expect any costs to be recoverable in rates.

Legislation was recently adopted that altered the Kansas renewable portfolio standard (RPS), ending all mandatory requirements in 2015. The mandate, which required 20% of our Kansas retail customer peak capacity requirements to be sourced from renewables by 2020, has been changed to a voluntary goal. We are currently in compliance as a result of purchased power agreements with Cloud County Windfarm, LLC and Elk River Windfarm, LLC.

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Retirement and Other Employee Benefits

3 Months Ended

Mar. 31, 2016

Retirement and Other Employee Benefits

Retirement and Other Employee Benefits

Note 8 — Retirement and Other Employee Benefits

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

	Three months ended March 31,
	Pension						SERP						OPEB
	2016			2015			2016			2015			2016			2015
Service cost	$	1,949		$	1,883		$	45		$	43		$	813		$	920
Interest cost	2,633			2,503			108			92			1,156			1,164
Expected return on plan assets	(3,465		)	(3,390		)	—			—			(1,374		)	(1,312		)
Amortization of prior service cost (1)	(157		)	(157		)	(3		)	(11		)	(253		)	(253		)
Amortization of net actuarial loss (1)	2,106			2,345			139			140			258			681
Net periodic benefit cost	$	3,066		$	3,184		$	289		$	264		$	600		$	1,200

	Twelve months ended March 31,
	Pension						SERP						OPEB
	2016			2015			2016			2015			2016			2015
Service cost	$	7,508		$	6,722		$	161		$	167		$	3,606		$	2,914
Interest cost	10,408			10,589			398			393			4,663			4,442
Expected return on plan assets	(13,643		)	(13,173		)	—			—			(5,258		)	(4,916		)
Amortization of prior service cost (1)	(630		)	156			(35		)	(17		)	(1,011		)	(1,011		)
Amortization of net actuarial loss (1)	9,795			7,308			596			539			2,324			1,420
Net periodic benefit cost	$	13,438		$	11,602		$	1,120		$	1,082		$	4,324		$	2,849

(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. Employees hired after June 1, 2014 will not receive a subsidy for healthcare benefits upon retirement.

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 $12.4 million during 2016. 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 $2.6 million during 2016. The actual minimum funding requirements for both pension and OPEB will be determined based on the results of the actuarial valuations.

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Equity Compensation

3 Months Ended

Mar. 31, 2016

Equity Compensation

Equity Compensation

Note 9 — Equity Compensation

Our time-vested restricted stock awards and performance-based restricted stock awards are valued as liability awards, in accordance with fair value guidelines. We allow qualified individuals 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 2016 (the effect of which is included in the table below). We had unrecognized compensation expense of $2.3 million as of March 31, 2016 which will be recognized over the remaining requisite service period.

We recognized the following amounts in compensation expense and tax benefits for all of our stock-based awards and programs for the applicable periods ended March 31 (in thousands):

	Three Months Ended				Twelve Months Ended
	2016		2015		2016		2015
Compensation expense	$	2,076	$	742	$	5,614	$	3,081
Tax benefit recognized	777		271		2,082		1,127

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 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. In addition, if a change in control occurs during the vesting period, a pro-rata portion of the time-vested restricted stock awards will vest upon such change in control, and any portion of such awards that remains unvested immediately after the change in control will be forfeited.

A summary of time vested restricted stock activity under the plan for 2015 and 2016 is presented in the table below:

	2016				2015
			Weighted				Weighted
	Number of		Average Grant		Number of		Average Grant
	shares		Date Fair Value		shares		Date Fair Value
Outstanding at January 1,	55,600		$	24.60	41,000		$	21.89
Granted	18,400		29.53		19,000		30.40
Distributed	(18,500	)	21.36		(1,654	)	21.92
Forfeited shares	0				(2,746	)	25.91
Outstanding at March 31	55,500		$	27.31	55,600		$	24.60

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.

If employment terminates during the performance period because of death, retirement, or disability, the individual is entitled to a pro-rata portion of the performance-based restricted stock awards such individual would otherwise have earned. If employment is terminated during the performance period for reasons other than those listed above, the performance-based restricted stock awards will be forfeited on the date of the termination unless the Compensation Committee of the Board of Directors determines, in its sole discretion, that the individual is entitled to a pro-rata portion of such award.  In addition, if a change in control occurs during the performance period, a pro-rata portion of the target performance-based restricted stock awards will vest and be distributed upon such change in control. At the end of the performance period, the number of shares earned, determined without regard to the special change in control vesting provisions will be determined and such amount, less the number of shares distributed upon the change in control, shall be distributed.

In connection with the Merger Agreement, we amended outstanding performance-based restricted stock awards to provide that, effective upon and subject to the occurrence of the Merger under the Merger Agreement, each performance-based restricted stock award outstanding immediately prior to the effective time of the Merger will be converted into the right to receive a lump sum in cash equal to the merger consideration under the Merger Agreement, multiplied by the target number of shares under the award.  (See Note 13 for further discussion of the Merger Agreement).

Non-vested performance-based restricted stock awards (based on target number) as of March 31, 2016 and 2015 and changes during the three months ended March 31, 2016 and 2015 were as follows:

	2016				2015
	Number of shares		Weighted Average Grant Date Price		Number of shares		Weighted Average Grant Date Price
Outstanding at January 1,	69,021		$	24.38	63,300		$	21.74
Target shares granted	22,400		$	29.53	21,800		$	30.40
Shares issued in excess of target	18,403		$	21.36	3,653		$	30.55
Shares awarded	(43,036	)	$	21.36	(13,653	)	$	30.55
Forfeited shares	—		$	—	(6,079	)	$	24.10
Target shares not awarded	—		$	—	—		$	—
Granted, nonvested at March 31,	66,788		$	27.22	69,021		$	24.38

Stock Unit Plan for Directors

Our Stock Unit Plan for directors (Stock Unit Plan) provides a stock-based compensation program for directors.  This plan enhances our ability to attract and retain competent and experienced directors and allows the directors the opportunity to accumulate compensation in the form of common stock units. The Stock Unit Plan also provides directors the opportunity to convert previously earned cash retirement benefits to common stock units.  All eligible directors who had benefits under the prior cash retirement plan converted their cash retirement benefits to common stock units.

Each common stock unit earns dividends in the form of common stock units and can be redeemed for shares of common stock.  In connection with the Merger Agreement, we amended the Stock Unit Plan to provide that, effective upon and subject to the occurrence of the Merger under the Merger Agreement, each stock unit outstanding immediately prior to the effective time of the Merger will be converted into the right to receive in cash the merger consideration under the Merger Agreement, with interest at the prime rate from the effective time of the Merger until the payment date under the plan. (See Note 13 for further discussion of the Merger Agreement).

The number of units granted annually is computed by dividing an annual credit (determined by the Compensation Committee) by the fair market value of our common stock on January 1 of the year the units are granted. Common stock unit dividends are computed based on the fair market value of our stock on the dividend’s record date.  We record the related compensation expense at the time we make the accrual for the directors’ benefits as the directors provide services. Shares accrued to directors’ accounts and shares available for issuance under this plan at March 31, 2016 and 2015 are shown in the table below:

	2016	2015
Shares accrued to directors’ accounts	160,124	164,085
Shares available for issuance	656,737	685,996

Units accrued for service and dividends as well as units redeemed for common stock at March 31, 2016 and 2015 are shown in the table below:

	2016	2015
Units accrued for service and dividends	23,698	25,187
Units redeemed for common stock	21,246	28,991

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Regulated Operating Expense

3 Months Ended

Mar. 31, 2016

Regulated Operating Expense

Regulated Operating Expense

Note 10 - Regulated Operating Expense

The following table sets forth the major components comprising “regulated operating expenses” under “Operating revenue deductions” on our consolidated statements of income (in thousands) for all periods presented ended March 31:

	Three Months Ended		Three Months Ended		Twelve Months Ended		Twelve Months Ended
	2016		2015		2016		2015
Electric transmission and distribution expense	$	6,836	$	7,100	$	28,629	$	28,221
Natural gas transmission and distribution expense	706		677		2,727		2,365
Power operation expense (other than fuel)	4,053		5,317		16,999		17,415
Customer accounts and assistance expense	2,731		2,704		10,965		11,106
Employee pension expense (1)	2,625		2,684		10,727		10,648
Employee healthcare expense (1)	2,245		2,234		10,173		9,656
General office supplies and expense	4,339		2,834		15,944		13,666
Administrative and general expense	4,116		4,556		14,423		14,716
Allowance for uncollectible accounts	79		327		1,833		2,975
Miscellaneous expense	115		118		425		603
Total	$	27,845	$	28,551	$	112,845	$	111,371

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

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Segment Information

3 Months Ended

Mar. 31, 2016

Segment Information

Segment Information

Note 11— Segment Information

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

	For the quarter ended March 31,
	2016
	Electric		Gas		Other		Eliminations			Total
Statement of Income Information
Revenues	$	134,363	$	15,113	$	2,184	$	(345	)	$	151,315
Depreciation and amortization	18,916		996		491		—			20,403
Federal and state income taxes	7,568		799		273		—			8,640
Operating income	20,507		2,293		443		—			23,243
Interest income	4		10		24		(29		)	9
Interest expense	10,688		969		—		(29		)	11,628
Income from AFUDC (debt and equity)	2,754		4		—		—			2,758
Net income	12,240		1,326		443		—			14,009
Capital Expenditures	$	33,167	$	863	$	419	$	—		$	34,449

	For the quarter ended March 31,
	2015
	Electric		Gas		Other		Eliminations			Total
Statement of Income Information
Revenues	$	142,641	$	19,818	$	2,430	$	(345	)	$	164,544
Depreciation and amortization	18,589		972		459		—			20,020
Federal and state income taxes	7,202		1,126		443		—			8,771
Operating income	21,214		2,788		711		—			24,713
Interest income	2		12		9		(12		)	11
Interest expense	10,091		965		—		(12		)	11,044
Income from AFUDC (debt and equity)	1,541		1		—		—			1,542
Net income	12,096		1,822		719		—			14,637
Capital Expenditures	$	52,263	$	683	$	609	$	—		$	53,555

	For the twelve months ended March 31,
	2016
	Electric		Gas		Other		Eliminations			Total
Statement of Income Information
Revenues	$	546,808	$	36,997	$	9,918	$	(1,379	)	$	592,344
Depreciation and amortization	75,059		3,947		1,927		—			80,933
Federal and state income taxes	31,489		473		1,719		—			33,681
Operating income	87,165		4,657		2,756		—			94,578
Interest income	135		35		62		(88		)	144
Interest expense	41,903		3,871		—		(88		)	45,686
Income from AFUDC (debt and equity)	8,893		17		—		—			8,910
Net income	52,384		791		2,794		—			55,969
Capital Expenditures	$	150,016	$	5,369	$	2,032	$	—		$	157,417

	For the twelve months ended March 31,
	2015
	Electric		Gas		Other		Eliminations			Total
Statement of Income Information
Revenues	$	582,043	$	47,051	$	9,437	$	(1,330	)	$	637,201
Depreciation and amortization	69,547		3,822		1,895		—			75,264
Federal and state income taxes	32,692		1,519		1,660		—			35,871
Operating income	86,176		6,289		2,760		—			95,225
Interest income	7		25		27		(39		)	20
Interest expense	38,635		3,863		—		(39		)	42,459
Income from AFUDC (debt and equity)	9,408		59		—		—			9,467
Net Income	55,679		2,457		2,699		—			60,835
Capital Expenditures	$	218,696	$	5,348	$	2,303	$	—		$	226,347

	As of March 31, 2016
($-000’s)	Electric		Gas(1)		Other		Eliminations			Total
Balance Sheet Information
Total assets	$	2,335,112	$	129,987	$	38,417	$	(52,590	)	$	2,450,926

(1) Includes goodwill of $39,492.

	As of December 31, 2015
($-000’s)	Electric		Gas(1)		Other		Eliminations			Total
Balance Sheet Information
Total assets	$	2,331,705	$	127,359	$	38,299	$	(50,718	)	$	2,446,645

(1) Includes goodwill of $39,492.

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Income Taxes

3 Months Ended

Mar. 31, 2016

Income Taxes

Income Taxes

Note 12— Income Taxes

The following table shows our provision for income taxes (in millions) and our consolidated effective federal and state income tax rates for the applicable periods ended March 31,:

	Three Months Ended						Twelve Months Ended
	2016			2015			2016			2015
Consolidated provision for income taxes	$	8.6		$	8.8		$	33.7		$	35.9
Consolidated effective federal and state income tax rates	38.1		%	37.5		%	37.6		%	37.1		%

The effective income tax rate for the three and twelve month periods ended March 31, 2016 is higher than comparable periods in 2015 primarily due to lower equity AFUDC income in 2016 compared to 2015.

We do not have any unrecognized tax benefits as of March 31, 2016. We did not recognize any significant interest or penalties in any of the periods presented. We do not expect any significant changes to our unrecognized tax benefits over the next twelve months.

The “Protecting Americans from Tax Hikes” Act (the “Act”) was signed into law on December 18, 2015. The Act restored several expired business tax provisions, including bonus depreciation for 2015. Because of the reinstatement of bonus depreciation, we anticipate making no material income tax payments in 2016.

We generated $74.1 million of tax NOLs during 2014, mainly due to bonus depreciation. We intend to carry forward these tax NOLs, which, if unused, will expire in 2034. We estimate that we will utilize approximately $38.0 million of the 2014 tax NOLs on our 2015 return when filed.  As of March 31, 2016, we estimate there is $13.5 million of deferred tax assets remaining to be utilized related to the tax NOLs.

In 2010, we received $17.7 million of investment tax credits based on our investment in Iatan 2, which, if unused, will expire in 2030. We utilized $9.0 million of these credits on our 2013 tax return.  Due to the passage of the Act, we estimate we will not be able to use the remaining credits on our 2015 tax return, but expect to use them to offset future income tax liabilities. The tax credits will have no significant income statement impact because they will flow to our customers as we amortize the tax credits over the life of the plant.

On September 13, 2013, the IRS and the Treasury Department released final regulations under Sections 162(a) and 263(a) on the deduction and capitalization of expenditures related to tangible property. These regulations applied to tax years beginning on or after January 1, 2014, and we filed a Form 3115 with the IRS to change our tax accounting method to comply with the regulations.  As a result, we deducted approximately $29 million on our 2014 income tax return under IRS Code Section 481(a) as an adjustment required by the change in tax accounting method.

Our 2014 income tax return included another tax accounting method change regarding the deductibility of the Voluntary Employee Benefit Association (VEBA) plan activity. As a result, we deducted approximately $14 million as an adjustment required by the change in tax method of accounting.  These changes did not have a material impact on the effective tax rate.

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Mergers and Acquisitions

3 Months Ended

Mar. 31, 2016

Mergers and acquisitions.

Mergers and Acquisitions

Note 13 — Mergers and Acquisitions

Pending Merger with Liberty Utilities (Central) Co. and Liberty Sub Corp.

On February 9, 2016, Empire entered into an Agreement and Plan of Merger (the Merger Agreement) with Liberty Utilities (Central) Co., a Delaware corporation (Liberty Central), and Liberty Sub Corp., a Kansas corporation (Merger Sub), providing for the merger of Merger Sub with and into Empire, with Empire surviving the Merger as a wholly-owned subsidiary of Liberty Central (the Merger). Pursuant to the Merger Agreement, at the effective time of the Merger, each issued and outstanding share of Empire common stock (other than any shares owned by Empire or Algonquin Power & Utilities Corp. (APUC) or any of their respective subsidiaries or any shares for which appraisal rights have been perfected) will be cancelled and converted automatically into the right to receive $34.00 in cash, without interest.

The closing of the Merger is subject to certain conditions, including, among others, approval of Empire shareholders, expiration or termination of the applicable Hart-Scott-Rodino Act waiting period and receipt of all required regulatory approvals and consents, including from the Federal Energy Regulatory Commission, the Federal Communications Commission, the Arkansas Public Service Commission, the Kansas Corporation Commission, the Missouri Public Service Commission, the Oklahoma Corporation Commission and the Committee on Foreign Investment in the United States, which approvals and consents shall not, individually or in the aggregate, have or be reasonably likely to have a material adverse effect on the business, properties, financial condition or results of operations of Liberty Utilities Co. and its subsidiaries (including Empire and its subsidiaries), taken as a whole.

If Empire shareholders do not approve the Merger, or the Merger is not consummated by February 9, 2017, the Merger Agreement may terminate, although it may be extended six months in order to obtain certain required regulatory approvals. The Merger Agreement also provides for certain other termination rights for both Empire and Liberty Central. If either party terminates the Merger Agreement because Empire’s board of directors changes its recommendation, or, if within nine months after the termination of the Merger Agreement under certain circumstances, Empire shall have entered into a definitive agreement with respect to, or consummated, an alternative transaction, Empire must pay Liberty Central a termination fee of $53.0 million.  If the Merger Agreement is terminated under certain other circumstances, including the failure to obtain required regulatory approvals, failure to consummate the Merger after all closing conditions have been satisfied and a financing failure has occurred or a breach by Liberty Central of its regulatory cooperation covenants, Liberty Central must pay Empire a termination fee of $65.0 million.

Simultaneously with the execution of the Merger Agreement, Liberty Central delivered to Empire a guarantee agreement (the Guarantee Agreement) executed by APUC, the parent of Liberty Utilities Co.  The Guarantee Agreement provides for an unconditional and irrevocable guarantee by APUC of the full and prompt payment and performance, when due, of all obligations of Liberty Central and Merger Sub under the Merger Agreement.

In connection with entering into the Merger Agreement, Empire has incurred approximately $4.5 million of transaction costs as of March 31, 2016. We expect that the total transaction costs will be approximately $15 to $17 million, with approximately 50% payable in 2016 (assuming a 2017 closing date), of which $4.2 million was incurred in the first quarter of 2016.

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Recently Issued and Proposed Accounting Standards (Policies)

3 Months Ended

Mar. 31, 2016

Recently Issued and Proposed Accounting Standards

Recently Issued and Proposed Accounting Standards

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. In July 2015, the FASB approved a one year delay in the standard’s effective date. The new standard is now effective for interim and annual reporting periods beginning after December 15, 2017. We are evaluating the impact of the adoption of this standard.

Presentation of debt issuance costs:  In April 2015, the FASB issued revised guidance addressing the presentation requirements for debt issuance costs. Under the revised guidance, all costs incurred to issue debt are to be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability. The revised guidance is effective for interim and annual reporting periods beginning after December 15, 2015. The application of this standard resulted in $8.5 million in unamortized debt issuance costs being reclassified from deferred charges to long-term debt on the March 31, 2016 Consolidated Balance Sheet and $8.7 million in unamortized debt issuance costs being reclassified from deferred charges to long-term debt on the December 31, 2015 Consolidated Balance Sheet for comparative purposes.

Recognition and measurement of financial assets and financial liabilities:  In January 2016, the FASB issued revised guidance addressing the recognition, measurement, presentation and disclosure of financial instruments.  Under the revised guidance all equity investments (except those accounted for under the equity method of accounting or those that result in consolidation of the investee) are to be measured at fair value with the changes in fair value recognized in net income.  The amended guidance also addresses the impairment assessment of some equity investments, as well as disclosure requirements. The revised guidance is effective for interim and annual periods beginning after December 15, 2017.  The application of this standard is not expected to have a material impact on our results of operations, financial position or liquidity.

Leases:  In February 2016, the FASB issued new guidance on accounting for leases.  Under the new guidance a lessee will be required to recognize the assets and liabilities arising from leases on the balance sheet.  The new guidance also addresses the income statement treatment for leases.  Under the new guidance leases will be classified as either operating or financing based on criteria that are similar to the old guidance.  Lease expense will be recognized on a straight line basis for operating leases while expense for capital leases will be similar to the finance pattern utilized today.  The new guidance is effective for interim and annual periods beginning after December 15, 2018, with early adoption permitted.  We are evaluating the impact of the adoption of this standard.

Stock Compensation:  In March 2016 the FASB issued revised guidance on stock compensation.  The updated guidance is intended to simplify some aspects of the accounting for stock compensation such as the income tax impact, classification of awards as either equity or liabilities, and cash flow classification. This guidance will be effective for 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, 2015 for further information regarding recently issued and proposed accounting standards.

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Regulatory Matters (Tables)

3 Months Ended

Mar. 31, 2016

Regulatory Matters

Components of regulatory assets and liabilities

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

Regulatory Assets and Liabilities

	March 31, 2016			December 31, 2015
Regulatory Assets:
Current:
Under recovered fuel costs	$	89		$	196
Current portion of long-term regulatory assets	7,056			6,856
Regulatory assets, current	7,145			7,052
Long-term:
Pension and other postretirement benefits(1)	106,237			108,273
Income taxes	48,597			48,613
Deferred construction accounting costs(2)	14,886			14,977
Unamortized loss on reacquired debt	9,563			9,731
Unsettled derivative losses — electric segment	7,785			7,775
System reliability — vegetation management	3,346			3,604
Storm costs	3,389			3,531
Asset retirement obligation	8,644			7,722
Customer programs	6,112			5,942
Missouri solar initiative(3)	6,170			3,504
Current portion of long-term regulatory assets	(7,056		)	(6,856		)
Other	2,261			2,892
Regulatory assets, long-term	209,934			209,708
Total Regulatory Assets	$	217,079		$	216,760

	March 31, 2016			December 31, 2015
Regulatory Liabilities:
Current:
Over recovered fuel costs	$	6,789		$	5,280
Current portion of long-term regulatory liabilities	3,365			3,335
Regulatory liabilities, current	10,154			8,615
Long-term:
Costs of removal(4)	95,673			94,193
SWPA payment for Ozark Beach lost generation	13,580			14,213
Income taxes	11,194			11,244
Deferred construction accounting costs — fuel(5)	7,651			7,690
Unamortized gain on interest rate derivative	2,989			3,031
Pension and other postretirement benefits	1,698			1,745
Over recovered fuel costs	3,168			2,300
System reliability — vegetation management	1,320			1,320
Current portion of long-term regulatory liabilities	(3,365		)	(3,335		)
Other	493			56
Regulatory liabilities, long-term	134,401			132,457
Total Regulatory Liabilities	$	144,555		$	141,072

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

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

(3)  Resulting from the Missouri Clean Energy Initiative and consists of approximately 467 solar rebate applications processed and internal costs as of March 31, 2016 (compared to 262 as of December 31, 2015), resulting in solar rebate-related costs totaling approximately $6.2 million.

(4)  As part of our depreciation rates, we accrue the estimated cost of dismantling and removing plant from service upon retirement. The accrued cost of removal, upon retirement, is reclassified from accumulated depreciation to a regulatory liability. These reclassified amounts are reflected here. See the depreciation discussion under Note 1 and Note 2 Property, Plant and Equipment in our Annual Report on Form 10-K for the fiscal year ended December 31, 2015 for more detail.

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

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Risk Management and Derivative Financial Instruments (Tables)

3 Months Ended

Mar. 31, 2016

Risk Management and Derivative Financial Instruments

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

As of March 31, 2016 and December 31, 2015, we have recorded the following assets and liabilities representing the fair value of derivative financial instruments, (in thousands):

		March 31,		December 31,
ASSET DERIVATIVES		2016		2015
Hedging instruments	Balance Sheet Classification	Fair Value		Fair Value
Natural gas contracts, gas segment	Current assets	$	18	$	2
	Non-current assets and deferred charges — other	—		16
Natural gas contracts, electric segment	Current assets	—		—
	Non-current assets and deferred charges — other	—		—
Transmission congestion rights, electric segment	Current assets	590		1,293
Total derivatives assets		$	608	$	1,311

		March 31,		December 31,
LIABILITY DERIVATIVES		2016		2015
Hedging instruments	Balance Sheet Classification	Fair Value		Fair Value
Natural gas contracts, gas segment	Current liabilities	$	14	$	282
	Non-current liabilities and deferred credits	51		66
Natural gas contracts, electric segment	Current liabilities	4,729		4,190
	Non-current liabilities and deferred credits	3,822		3,630
Total derivatives liabilities		$	8,616	$	8,168

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

The following tables set forth “mark-to-market” pre-tax gains/(losses) from non-designated derivative instruments for the electric segment for each of the periods ended March 31, (in thousands):

Non-Designated Hedging Instruments  — Due to Regulatory Accounting Electric Segment	Balance Sheet  Classification of Gain /  (Loss) on Derivative	Amount of Gain / (Loss) Recognized on Balance  Sheet
		Three Months Ended						Twelve Months Ended
		2016			2015			2016			2015
Commodity contracts	Regulatory (assets)/liabilities	$	(1,709	)	$	(2,540	)	$	(6,022	)	$	(11,077	)
Transmission congestion rights	Regulatory (assets)/liabilities	122			1,105			3,987			13,434
Total Electric Segment		$	(1,587	)	$	(1,435	)	$	(2,035	)	$	2,357

Non-Designated Hedging Instruments  — Due to Regulatory Accounting Electric Segment	Statement of Income  Classification of Gain /  (Loss) on Derivative	Amount of Gain / (Loss) Recognized in Income  on Derivative
		Three Months Ended						Twelve Months Ended
		2016			2015			2016			2015
Commodity contracts	Fuel and purchased power expense	$	(1,698	)	$	(1,421	)	$	(8,392	)	$	(3,834	)
Transmission congestion rights	Fuel and purchased power expense	796			3,438			4,826			13,743
Total Electric Segment		$	(902	)	$	2,017		$	(3,566	)	$	9,909

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

		Dth Hedged				Procurement
Year	% Hedged	Physical	Financial	Average Price		Guidelines
Remainder 2016	56%	2,676,000	3,860,000	$	3.54	Up to 100%
2017	41%	782,900	5,210,000	$	3.35	60%
2018	20%	565,000	2,460,000	$	3.33	40%
2019	10%	—	1,460,000	$	2.96	20%
2020	—	—	—	—		10%

Schedule of transmission congestion rights (TCR)

At March 31, 2016, the following transmission congestion rights (TCR) have been obtained to hedge congestion risk in the SPP IM (dollars in thousands):

Year	Monthly MWH  Hedged	$ Value
2016	1,430	$	590

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

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 and illustrates our hedged position as of March 31, 2016 (Dth in thousands).

Season	Target % Hedged by September 1	Dth Hedged — Financial	Dth Hedged — Physical	Dth in Storage	Actual % Hedged
Nov. 2016 - Mar. 2017	50%	200,000	—	1,252,281	47%
Nov. 2017 - Mar. 2018	Up to 50%	280,000	—	—	9%
Nov. 2018 - Mar. 2019	Up to 20%	—	—	—	—

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

The following table sets forth “mark-to-market” pre-tax gains / (losses) from derivatives not designated as hedging instruments for the gas segment for each of the periods ended March 31 (in thousands).

		Amount of Gain / (Loss)
Non-Designated Hedging	Balance Sheet	Recognized on Balance Sheet
Instruments Due to Regulatory	Classification of Gain or	Three Months Ended						Twelve Months Ended
Accounting — Gas Segment	(Loss) on Derivative	2016			2015			2016			2015
Commodity contracts	Regulatory (assets)/ liabilities	$	(67	)	$	(17	)	$	(497	)	$	(478	)
Total - Gas Segment		$	(67	)	$	(17	)	$	(497	)	$	(478	)

Schedule of margin deposit assets

(in millions)	March 31, 2016		December 31, 2015
Margin deposit assets	$	10.3	$	11.2

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Fair Value Measurements (Tables)

3 Months Ended

Mar. 31, 2016

Fair Value Measurements

Schedule of transmission congestion rights (TCR) and commodity contracts measured at fair value

The following fair value hierarchy table presents information about our TCR and commodity contracts measured at fair value as of March 31, 2016 and December 31, 2015 (in thousands):

	Fair Value Measurements at Reporting Date Using
Description	Assets/(Liabilities) at Fair Value			Quoted Prices in Active Markets for Identical Assets/(Liabilities) (Level 1)			Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
				March 31, 2016
Derivative assets	$	608		$	18		$	590	$	—
Derivative liabilities	$	(8,616	)	$	(8,616	)	$	—	$	—
				December 31, 2015
Derivative assets	$	1,311		$	18		$	1,293	$	—
Derivative liabilities	$	(8,168	)	$	(8,168	)	$	—	$	—

*The only recurring measurements are derivative related.

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Commitments and Contingencies (Tables)

3 Months Ended

Mar. 31, 2016

Commitments and Contingencies

Schedule of physical gas, coal and transportation contracts

The following table sets forth our firm physical gas, coal and transportation contracts for the periods indicated as of March 31, 2016 (in millions).

	Firm physical gas and transportation contracts		Coal and coal transportation contracts
April 1, 2016 through December 31, 2016	$	21.8	$	12.2
January 1, 2017 through December 31, 2018	37.4		26.9
January 1, 2019 through December 31, 2020	28.8		10.5
January 1, 2021 and beyond	45.7		—

Summary of most significant environmental regulations affecting operations

The following list summarizes the most significant environmental regulations affecting our operations:

Regulations

Air Emissions - NOx and SO2

CAIR (Clean Air Interstate Rule)

CSAPR (Cross State Air Pollution Rule)

MATS (Mercury Air Toxic Standards)

NAAQS (National Ambient Air Quality Standards)

Greenhouse Gases (GHGs) — CO2

Surface Impoundments

Coal Ash Impoundments:

Asbury Power Plant

Riverton (capped and closed in 2014 as industrial (coal combustion waste) landfill)

Water Discharges

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Retirement and Other Employee Benefits (Tables)

3 Months Ended

Mar. 31, 2016

Retirement and Other Employee Benefits

Schedule of net periodic benefit pension cost

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

	Three months ended March 31,
	Pension						SERP						OPEB
	2016			2015			2016			2015			2016			2015
Service cost	$	1,949		$	1,883		$	45		$	43		$	813		$	920
Interest cost	2,633			2,503			108			92			1,156			1,164
Expected return on plan assets	(3,465		)	(3,390		)	—			—			(1,374		)	(1,312		)
Amortization of prior service cost (1)	(157		)	(157		)	(3		)	(11		)	(253		)	(253		)
Amortization of net actuarial loss (1)	2,106			2,345			139			140			258			681
Net periodic benefit cost	$	3,066		$	3,184		$	289		$	264		$	600		$	1,200

	Twelve months ended March 31,
	Pension						SERP						OPEB
	2016			2015			2016			2015			2016			2015
Service cost	$	7,508		$	6,722		$	161		$	167		$	3,606		$	2,914
Interest cost	10,408			10,589			398			393			4,663			4,442
Expected return on plan assets	(13,643		)	(13,173		)	—			—			(5,258		)	(4,916		)
Amortization of prior service cost (1)	(630		)	156			(35		)	(17		)	(1,011		)	(1,011		)
Amortization of net actuarial loss (1)	9,795			7,308			596			539			2,324			1,420
Net periodic benefit cost	$	13,438		$	11,602		$	1,120		$	1,082		$	4,324		$	2,849

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

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Equity Compensation (Tables)

3 Months Ended

Mar. 31, 2016

Equity Compensation

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

We recognized the following amounts in compensation expense and tax benefits for all of our stock-based awards and programs for the applicable periods ended March 31 (in thousands):

	Three Months Ended				Twelve Months Ended
	2016		2015		2016		2015
Compensation expense	$	2,076	$	742	$	5,614	$	3,081
Tax benefit recognized	777		271		2,082		1,127

Schedule of time vested restricted stock activity

	2016				2015
			Weighted				Weighted
	Number of		Average Grant		Number of		Average Grant
	shares		Date Fair Value		shares		Date Fair Value
Outstanding at January 1,	55,600		$	24.60	41,000		$	21.89
Granted	18,400		29.53		19,000		30.40
Distributed	(18,500	)	21.36		(1,654	)	21.92
Forfeited shares	0				(2,746	)	25.91
Outstanding at March 31	55,500		$	27.31	55,600		$	24.60

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

	2016				2015
	Number of shares		Weighted Average Grant Date Price		Number of shares		Weighted Average Grant Date Price
Outstanding at January 1,	69,021		$	24.38	63,300		$	21.74
Target shares granted	22,400		$	29.53	21,800		$	30.40
Shares issued in excess of target	18,403		$	21.36	3,653		$	30.55
Shares awarded	(43,036	)	$	21.36	(13,653	)	$	30.55
Forfeited shares	—		$	—	(6,079	)	$	24.10
Target shares not awarded	—		$	—	—		$	—
Granted, nonvested at March 31,	66,788		$	27.22	69,021		$	24.38

Schedule of shares accrued to directors' accounts and shares available for issuance under Stock Unit Plan for directors

	2016	2015
Shares accrued to directors’ accounts	160,124	164,085
Shares available for issuance	656,737	685,996

Schedule of units accrued and redeemed under Stock Unit Plan for directors

	2016	2015
Units accrued for service and dividends	23,698	25,187
Units redeemed for common stock	21,246	28,991

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Regulated Operating Expens (Tables)

3 Months Ended

Mar. 31, 2016

Regulated Operating Expense

Schedule of regulated operating expenses

The following table sets forth the major components comprising “regulated operating expenses” under “Operating revenue deductions” on our consolidated statements of income (in thousands) for all periods presented ended March 31:

	Three Months Ended		Three Months Ended		Twelve Months Ended		Twelve Months Ended
	2016		2015		2016		2015
Electric transmission and distribution expense	$	6,836	$	7,100	$	28,629	$	28,221
Natural gas transmission and distribution expense	706		677		2,727		2,365
Power operation expense (other than fuel)	4,053		5,317		16,999		17,415
Customer accounts and assistance expense	2,731		2,704		10,965		11,106
Employee pension expense (1)	2,625		2,684		10,727		10,648
Employee healthcare expense (1)	2,245		2,234		10,173		9,656
General office supplies and expense	4,339		2,834		15,944		13,666
Administrative and general expense	4,116		4,556		14,423		14,716
Allowance for uncollectible accounts	79		327		1,833		2,975
Miscellaneous expense	115		118		425		603
Total	$	27,845	$	28,551	$	112,845	$	111,371

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

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Segment Information (Tables)

3 Months Ended

Mar. 31, 2016

Segment Information

Schedule of statement of income information, balance sheet information and capital expenditures by business segments

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

	For the quarter ended March 31,
	2016
	Electric		Gas		Other		Eliminations			Total
Statement of Income Information
Revenues	$	134,363	$	15,113	$	2,184	$	(345	)	$	151,315
Depreciation and amortization	18,916		996		491		—			20,403
Federal and state income taxes	7,568		799		273		—			8,640
Operating income	20,507		2,293		443		—			23,243
Interest income	4		10		24		(29		)	9
Interest expense	10,688		969		—		(29		)	11,628
Income from AFUDC (debt and equity)	2,754		4		—		—			2,758
Net income	12,240		1,326		443		—			14,009
Capital Expenditures	$	33,167	$	863	$	419	$	—		$	34,449

	For the quarter ended March 31,
	2015
	Electric		Gas		Other		Eliminations			Total
Statement of Income Information
Revenues	$	142,641	$	19,818	$	2,430	$	(345	)	$	164,544
Depreciation and amortization	18,589		972		459		—			20,020
Federal and state income taxes	7,202		1,126		443		—			8,771
Operating income	21,214		2,788		711		—			24,713
Interest income	2		12		9		(12		)	11
Interest expense	10,091		965		—		(12		)	11,044
Income from AFUDC (debt and equity)	1,541		1		—		—			1,542
Net income	12,096		1,822		719		—			14,637
Capital Expenditures	$	52,263	$	683	$	609	$	—		$	53,555

	For the twelve months ended March 31,
	2016
	Electric		Gas		Other		Eliminations			Total
Statement of Income Information
Revenues	$	546,808	$	36,997	$	9,918	$	(1,379	)	$	592,344
Depreciation and amortization	75,059		3,947		1,927		—			80,933
Federal and state income taxes	31,489		473		1,719		—			33,681
Operating income	87,165		4,657		2,756		—			94,578
Interest income	135		35		62		(88		)	144
Interest expense	41,903		3,871		—		(88		)	45,686
Income from AFUDC (debt and equity)	8,893		17		—		—			8,910
Net income	52,384		791		2,794		—			55,969
Capital Expenditures	$	150,016	$	5,369	$	2,032	$	—		$	157,417

	For the twelve months ended March 31,
	2015
	Electric		Gas		Other		Eliminations			Total
Statement of Income Information
Revenues	$	582,043	$	47,051	$	9,437	$	(1,330	)	$	637,201
Depreciation and amortization	69,547		3,822		1,895		—			75,264
Federal and state income taxes	32,692		1,519		1,660		—			35,871
Operating income	86,176		6,289		2,760		—			95,225
Interest income	7		25		27		(39		)	20
Interest expense	38,635		3,863		—		(39		)	42,459
Income from AFUDC (debt and equity)	9,408		59		—		—			9,467
Net Income	55,679		2,457		2,699		—			60,835
Capital Expenditures	$	218,696	$	5,348	$	2,303	$	—		$	226,347

	As of March 31, 2016
($-000’s)	Electric		Gas(1)		Other		Eliminations			Total
Balance Sheet Information
Total assets	$	2,335,112	$	129,987	$	38,417	$	(52,590	)	$	2,450,926

(1) Includes goodwill of $39,492.

	As of December 31, 2015
($-000’s)	Electric		Gas(1)		Other		Eliminations			Total
Balance Sheet Information
Total assets	$	2,331,705	$	127,359	$	38,299	$	(50,718	)	$	2,446,645

(1) Includes goodwill of $39,492.

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Income Taxes (Tables)

3 Months Ended

Mar. 31, 2016

Income Taxes

Schedule of provision for income taxes and consolidated effective federal and state income tax rates

The following table shows our provision for income taxes (in millions) and our consolidated effective federal and state income tax rates for the applicable periods ended March 31,:

	Three Months Ended						Twelve Months Ended
	2016			2015			2016			2015
Consolidated provision for income taxes	$	8.6		$	8.8		$	33.7		$	35.9
Consolidated effective federal and state income tax rates	38.1		%	37.5		%	37.6		%	37.1		%

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Summary of Significant Accounting Policies (Details)	3 Months Ended
	Mar. 31, 2016 segment item
Summary of Significant Accounting Policies
Number of business segments | segment	3
Number of towns to which water service is provided	3
Number of communities provided natural gas distribution	48

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Recently Issued and Proposed Accounting Standards (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2016	Dec. 31, 2015
Scenario, Adjustment | Accounting Standards Update 2015-03 Simplifying the Presentation of Debt Issuance Costs
Recently Issued and Proposed Accounting Standards
Change in financial position	$ 8.5	$ 8.7

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Regulatory Matters (Details) $ in Thousands	3 Months Ended	12 Months Ended
	Mar. 31, 2016 USD ($) item	Dec. 31, 2015 USD ($) item
Regulatory Assets:
Regulatory assets, current	$ 7,145	$ 7,052
Regulatory assets, long-term	209,934	209,708
Total Regulatory Assets	217,079	216,760
Regulatory Liabilities:
Regulatory liabilities, current	10,154	8,615
Regulatory liabilities, long-term	134,401	132,457
Total Regulatory Liabilities	144,555	141,072
Over recovered fuel costs
Regulatory Liabilities:
Regulatory liabilities, current	6,789	5,280
Regulatory liabilities, long-term	3,168	2,300
System reliability - vegetation management
Regulatory Liabilities:
Regulatory liabilities, long-term	1,320	1,320
Current portion of long-term regulatory liabilities
Regulatory Liabilities:
Regulatory liabilities, current	3,365	3,335
Other
Regulatory Liabilities:
Regulatory liabilities, long-term	493	56
Costs of removal
Regulatory Liabilities:
Regulatory liabilities, long-term	95,673	94,193
SWPA payment for Ozark Beach lost generation
Regulatory Liabilities:
Regulatory liabilities, long-term	13,580	14,213
Income taxes
Regulatory Liabilities:
Regulatory liabilities, long-term	11,194	11,244
Deferred construction accounting costs - fuel
Regulatory Liabilities:
Regulatory liabilities, long-term	7,651	7,690
Unamortized gain on interest rate derivative
Regulatory Liabilities:
Regulatory liabilities, long-term	2,989	3,031
Pension and other postretirement benefits
Regulatory Liabilities:
Regulatory liabilities, long-term	1,698	1,745
Under recovered fuel costs
Regulatory Assets:
Regulatory assets, current	89	196
Current portion of long-term regulatory assets
Regulatory Assets:
Regulatory assets, current	7,056	6,856
Pension and other postretirement benefits
Regulatory Assets:
Regulatory assets, long-term	106,237	108,273
Income taxes
Regulatory Assets:
Regulatory assets, long-term	48,597	48,613
Deferred construction accounting costs
Regulatory Assets:
Regulatory assets, long-term	14,886	14,977
Unamortized loss on reacquired debt
Regulatory Assets:
Regulatory assets, long-term	9,563	9,731
System reliability - vegetation management
Regulatory Assets:
Regulatory assets, long-term	3,346	3,604
Storm costs
Regulatory Assets:
Regulatory assets, long-term	3,389	3,531
Asset retirement obligation.
Regulatory Assets:
Regulatory assets, long-term	8,644	7,722
Customer programs
Regulatory Assets:
Regulatory assets, long-term	6,112	5,942
Missouri solar initiative
Regulatory Assets:
Regulatory assets, long-term	$ 6,170	$ 3,504
Number of solar rebate applications processed | item	467	262
Other
Regulatory Assets:
Regulatory assets, long-term	$ 2,261	$ 2,892
Electric | Unsettled derivative losses- electric segment
Regulatory Assets:
Regulatory assets, long-term	$ 7,785	$ 7,775

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Risk Management and Derivative Financial Instruments (Details) - USD ($) $ in Thousands	Mar. 31, 2016	Dec. 31, 2015
Fair value of derivative financial instruments
Current assets	$ 608	$ 1,295
Total derivatives assets	608	1,311
Current liabilities	4,743	4,472
Non-current liabilities and deferred credits	3,873	3,696
Total derivatives liabilities	8,616	8,168
Hedging instruments | Commodity contracts | Gas
Fair value of derivative financial instruments
Current assets	18	2
Non-current other assets		16
Current liabilities	14	282
Non-current liabilities and deferred credits	51	66
Hedging instruments | Commodity contracts | Electric
Fair value of derivative financial instruments
Current liabilities	4,729	4,190
Non-current liabilities and deferred credits	3,822	3,630
Hedging instruments | Transmission congestion rights (TCR) | Electric
Fair value of derivative financial instruments
Current assets	$ 590	$ 1,293

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Risk Management and Derivative Financial Instruments (Details 2) - USD ($) $ in Thousands	3 Months Ended		12 Months Ended
	Mar. 31, 2016	Mar. 31, 2015	Mar. 31, 2016	Mar. 31, 2015
Electric
Gain / (Loss) on derivatives
Unrealized net losses applicable to financial instruments which will settle in next twelve months	$ 4,700		$ 4,700
Period within which financial instruments will settle	12 months
Amount of Gain/(Loss) Recognized on Balance Sheet	$ (1,587)	$ (1,435)	(2,035)	$ 2,357
Amount of Gain / (Loss) Recognized in Income on Derivative	(902)	2,017	(3,566)	9,909
Gas
Gain / (Loss) on derivatives
Amount of Gain/(Loss) Recognized on Balance Sheet	(67)	(17)	(497)	(478)
Commodity contracts | Electric
Gain / (Loss) on derivatives
Amount of Gain/(Loss) Recognized on Balance Sheet	(1,709)	(2,540)	(6,022)	(11,077)
Amount of Gain / (Loss) Recognized in Income on Derivative	(1,698)	(1,421)	(8,392)	(3,834)
Commodity contracts | Gas
Gain / (Loss) on derivatives
Amount of Gain/(Loss) Recognized on Balance Sheet	(67)	(17)	(497)	(478)
Transmission congestion rights (TCR) | Electric
Gain / (Loss) on derivatives
Amount of Gain/(Loss) Recognized on Balance Sheet	122	1,105	3,987	13,434
Amount of Gain / (Loss) Recognized in Income on Derivative	$ 796	$ 3,438	$ 4,826	$ 13,743

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Risk Management and Derivative Financial Instruments (Details 3) $ in Thousands	3 Months Ended
	Mar. 31, 2016 USD ($) item MWh $ / item
Transmission congestion rights (TCR) - 2015
Procurement guidelines
Monthly MWH Hedged | MWh	1,430.0
Monthly MWH Hedged, estimated fair value | $	$ 590
Electric | Natural Gas Usage - Remainder 2016
Volumes and percentage of anticipated volume of natural gas usage
% Hedged	56.00%
Dth Hedged Physical	2,676,000
Dth Hedged Financial	3,860,000
Average Price (in dollars per dth) | $ / item	3.540
Electric | Natural Gas Usage - 2017
Volumes and percentage of anticipated volume of natural gas usage
% Hedged	41.00%
Dth Hedged Physical	782,900
Dth Hedged Financial	5,210,000
Average Price (in dollars per dth) | $ / item	3.350
Electric | Natural Gas Usage - 2018
Volumes and percentage of anticipated volume of natural gas usage
% Hedged	20.00%
Dth Hedged Physical	565,000
Dth Hedged Financial	2,460,000
Average Price (in dollars per dth) | $ / item	3.330
Electric | Natural Gas Forward 2019
Volumes and percentage of anticipated volume of natural gas usage
% Hedged	10.00%
Dth Hedged Financial	1,460,000
Average Price (in dollars per dth) | $ / item	2.960
Electric | Current Year Procurement Guidelines
Procurement guidelines
Maximum percentage of volume to be hedged in any given month	100.00%
Maximum flexibility to hedge any future year's expected requirements (as a percent)	80.00%
Electric | First Year Procurement Guidelines
Volumes and percentage of anticipated volume of natural gas usage
% Hedged	60.00%
Electric | Second Year Procurement Guidelines
Volumes and percentage of anticipated volume of natural gas usage
% Hedged	40.00%
Electric | Third Year Procurement Guidelines
Volumes and percentage of anticipated volume of natural gas usage
% Hedged	20.00%
Electric | Fourth Year Procurement Guidelines
Volumes and percentage of anticipated volume of natural gas usage
% Hedged	10.00%
Electric | High end of range | Current Year Procurement Guidelines
Volumes and percentage of anticipated volume of natural gas usage
% Hedged	100.00%

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Risk Management and Derivative Financial Instruments (Details 4) $ in Millions	3 Months Ended
	Mar. 31, 2016 USD ($) item	Dec. 31, 2015 USD ($)
Contingent Features
Derivative instruments with the credit-risk-related contingent features that are in a liability position | $	$ 0.0
Collateral posted | $	0.0
Margin deposit liabilities | $	0.0
Margin deposit assets
Margin deposit assets | $	$ 10.3	$ 11.2
Gas
Price Risk Mitigation for Gas Segment
Target percentage of storage capacity utilization	95.00%
Volume of storage in pipelines that serve customers (in Dth)	1,300,000
Number of pipelines that serve customers (in units)	3
Storage capacity utilized (as a percent)	61.00%
Number of future winter seasons for which minimum of expected gas usage is hedged (in seasons)	2
Gas | Nov. 2016 - Mar. 2017
Gas Usage Hedged By Winter Season
Target % Hedged	50.00%
Dth Hedged Financial	200,000
Dth in Storage	1,252,281
Actual % Hedged	47.00%
Gas | High end of range | Nov. 2017 - Mar. 2018
Gas Usage Hedged By Winter Season
Target % Hedged	50.00%
Dth Hedged Financial	280,000
Actual % Hedged	9.00%
Gas | High end of range | Nov. 2018 - Mar. 2019
Gas Usage Hedged By Winter Season
Target % Hedged	20.00%

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Fair Value Measurements (Details) - Recurring basis - USD ($) $ in Thousands	Mar. 31, 2016	Dec. 31, 2015
Fair Value Measurements at Reporting Date
Derivative assets	$ 608	$ 1,311
Derivative liabilities	(8,616)	(8,168)
Quoted Prices in Active Markets for Identical Assets/(Liabilities) (Level 1)
Fair Value Measurements at Reporting Date
Derivative assets	18	18
Derivative liabilities	(8,616)	(8,168)
Significant Other Observable Inputs (Level 2)
Fair Value Measurements at Reporting Date
Derivative assets	$ 590	$ 1,293

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Fair Value Measurements (Details 2) - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015
Long-Term Debt
Carrying amount of total long-term debt exclusive of capital leases	$ 851	$ 851
Fair market value	$ 856	$ 815

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Financing (Details) $ in Millions	3 Months Ended
	Mar. 31, 2016 USD ($) item
Unsecured revolving credit facility
Schedule of debt instruments
Unsecured revolving credit facility	$ 200.0
Additional borrowing capacity	$ 75.0
Number of extensions | item	2
Extension period	1 year
Maximum percentage of total indebtedness to total capitalization under the financial covenants of the credit facility agreement	65.00%
Percentage of total indebtedness to total capitalization under the financial covenants of the credit facility agreement	52.00%
Aggregate amount of default on other indebtedness subject to cross-default under the terms of the credit facility.	$ 25.0
Outstanding borrowings	0.0
Swingline loan
Schedule of debt instruments
Unsecured revolving credit facility	20.0
Letters of credit
Schedule of debt instruments
Unsecured revolving credit facility	20.0
Commercial paper
Schedule of debt instruments
Amount of credit facility used to back up outstanding commercial paper borrowings	$ 19.0

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Commitments and Contingencies (Detail) $ in Millions			3 Months Ended
	Dec. 15, 2008	Dec. 15, 2005	Mar. 31, 2016 USD ($) Office item MW
Electric | Power Plant Mercury And Air Toxics Rule
Commitments and Contingencies
Cost related to pre-engineering, site preparation activities and contract cost project to date			$ 163.4
Term of Capital Expenditure Plan			5 years
Electric | Low end of range | Power Plant Mercury And Air Toxics Rule
Commitments and Contingencies
Estimated project cost			$ 165.0
Electric | High end of range | Power Plant Mercury And Air Toxics Rule
Commitments and Contingencies
Estimated project cost			175.0
Firm Physical gas and transportation contracts
Commitments and Contingencies
April 1, 2016 through December 31, 2016			21.8
January 1, 2017 through December 31, 2018			37.4
January 1, 2019 through December 31, 2020			28.8
January 1, 2021 and beyond			45.7
Coal and coal transportation contracts
Commitments and Contingencies
April 1, 2016 through December 31, 2016			12.2
January 1, 2017 through December 31, 2018			26.9
January 1, 2019 through December 31, 2020			$ 10.5
Purchased power
Commitments and Contingencies
Number of purchased power agreement | item			3
Purchased power | Plum Point Energy Station
Commitments and Contingencies
Energy capacity (in megawatts) | MW			670
Amount of energy capacity owned (in megawatts) | MW			50
Amount of long-term contract obligation			$ 275.1
Purchased power | Cloud County Windfarm
Commitments and Contingencies
Energy capacity (in megawatts) | MW			105
Period of the average cost that is used as a basis for determining the maximum annual payments	20 years
Purchased power | Cloud County Windfarm | Low end of range
Commitments and Contingencies
Amount of annual payments contingent upon output of the facility			$ 0.0
Purchased power | Cloud County Windfarm | High end of range
Commitments and Contingencies
Amount of annual payments contingent upon output of the facility			$ 14.6
Purchased power | Elk River Windfarm
Commitments and Contingencies
Energy capacity (in megawatts) | MW			150
Period of the average cost that is used as a basis for determining the maximum annual payments		20 years
Purchased power | Elk River Windfarm | Low end of range
Commitments and Contingencies
Amount of annual payments contingent upon output of the facility			$ 0.0
Purchased power | Elk River Windfarm | High end of range
Commitments and Contingencies
Amount of annual payments contingent upon output of the facility			16.9
Leases
Commitments and Contingencies
Gross amount of assets recorded under capital leases			$ 5.3
Leases | Electric
Commitments and Contingencies
Number of unit trains under short-term operating leases | item			2
Leases | Gas
Commitments and Contingencies
Number of office facilities under short-term operating leases | Office			1
Leases | Plum Point Energy Station
Commitments and Contingencies
Number of railcars under capital leases | item			108

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Commitments and Contingencies (Details 2) $ in Thousands		3 Months Ended
	Jan. 09, 2016 state	Mar. 31, 2016 USD ($) item	Dec. 31, 2015 USD ($)
Environmental Laws And Regulations
Number of states initiating legal challenges to invalidate rule | state	27
Regulatory assets of Missouri solar initiative		$ 209,934	$ 209,708
Surface Impoundments | Asbury Power Plant | Electric
Environmental Laws And Regulations
Asset retirement obligation		5,400
Surface Impoundments | Asbury Power Plant | Electric | High end of range
Environmental Laws And Regulations
Potential cost for construction of new landfill and conversion of existing ash handling from wet to dry system(s)		15,000
Surface Impoundments | Iatan | Electric
Environmental Laws And Regulations
Asset retirement obligation		$ 4,400
Renewable Energy | Electric
Environmental Laws And Regulations
Minimum percentage of Missouri retail sales required to generate or purchase electricity in 2014-2017		5.00%
Minimum percentage of Missouri retail sales required to generate or purchase electricity by 2018-2020		10.00%
Minimum percentage of Missouri retail sales required to generate or purchase electricity by 2021		15.00%
Percentage of Missouri retail sales required to generate or purchase solar energy		2.00%
Number of solar rebate applications processed in Missouri solar initiative | item		467
Rebate Commitments in Missouri solar initiative		$ 6,200
Regulatory assets of Missouri solar initiative		$ 6,200
Percentage of Kansas retail customer peak capacity required to be sourced from renewable energy by 2020		20.00%
Green House Gases
Environmental Laws And Regulations
Percentage of carbon emission reduction from 2005 baseline levels by 2030, required by the proposed Clean Power Plan		32.00%
Number of plan types for states to choose to meet their goals | item		2

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Retirement and Other Employee Benefits (Details) - USD ($) $ in Thousands	3 Months Ended		12 Months Ended
	Mar. 31, 2016	Mar. 31, 2015	Mar. 31, 2016	Mar. 31, 2015
Pension Benefits
Net Periodic Pension Benefit Cost:
Service cost	$ 1,949	$ 1,883	$ 7,508	$ 6,722
Interest cost	2,633	2,503	10,408	10,589
Expected return on plan assets	(3,465)	(3,390)	(13,643)	(13,173)
Amortization of prior service cost	(157)	(157)	(630)	156
Amortization of net actuarial loss	2,106	2,345	9,795	7,308
Net periodic benefit cost	3,066	3,184	13,438	11,602
Pension contributions	12,400
SERP
Net Periodic Pension Benefit Cost:
Service cost	45	43	161	167
Interest cost	108	92	398	393
Amortization of prior service cost	(3)	(11)	(35)	(17)
Amortization of net actuarial loss	139	140	596	539
Net periodic benefit cost	289	264	1,120	1,082
OPEB
Net Periodic Pension Benefit Cost:
Service cost	813	920	3,606	2,914
Interest cost	1,156	1,164	4,663	4,442
Expected return on plan assets	(1,374)	(1,312)	(5,258)	(4,916)
Amortization of prior service cost	(253)	(253)	(1,011)	(1,011)
Amortization of net actuarial loss	258	681	2,324	1,420
Net periodic benefit cost	600	$ 1,200	$ 4,324	$ 2,849
Pension contributions	$ 2,600
Healthcare benefits
Net Periodic Pension Benefit Cost:
Eligible age	55 years
Minimum service period for eligibility	5 years

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Equity Compensation (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended		12 Months Ended
	Mar. 31, 2016	Mar. 31, 2015	Mar. 31, 2016	Dec. 31, 2015	Mar. 31, 2015
Equity Compensation
Unrecognized compensation expense	$ 2,300		$ 2,300
Compensation Expense	2,076	$ 742	5,614		$ 3,081
Tax Benefit Recognized	$ 777	$ 271	$ 2,082		$ 1,127
Time-Vested Restricted Stock Awards
Assumptions used for estimating fair value of grants outstanding
Vesting period	3 years
Changes in restricted stock awards
Nonvested, balance at the beginning of the period (in shares)	55,600	41,000	55,600	41,000
Granted (in shares)	18,400	19,000
Distributed (in shares)	(18,500)	(1,654)
Forfeited shares (in shares)		(2,746)
Nonvested, balance at the end of the period (in shares)	55,500	55,600	55,500	55,600	55,600
Weighted Average Grant Date Fair Value
Nonvested, balance at the beginning of the period (in dollars per share)	$ 24.60	$ 21.89	$ 24.60	$ 21.89
Granted (in dollars per share)	29.53	30.40
Distributed (in dollars per share)	21.36	21.92
Forfeited shares ( in dollars per share)				25.91
Nonvested, balance at the end of the period (in dollars per share)	$ 27.31	$ 24.60	$ 27.31	$ 24.60	$ 24.60
Performance-Based Restricted Stock Awards
Changes in restricted stock awards
Nonvested, balance at the beginning of the period (in shares)	69,021	63,300	69,021	63,300
Target shares granted (in shares)	22,400	21,800
Shares issued in excess of target (in shares)	18,403	3,653
Shares awarded (in shares)	(43,036)	(13,653)
Forfeited shares (in shares)		(6,079)
Nonvested, balance at the end of the period (in shares)	66,788	69,021	66,788	69,021	69,021
Weighted Average Grant Date Fair Value
Nonvested, balance at the beginning of the period (in dollars per share)	$ 24.38	$ 21.74	$ 24.38	$ 21.74
Target shares granted (in dollars per share)	$ 29.53	$ 30.40
Shares issued in excess of target (in dollars per share)	21.36	30.55
Shares awarded (in dollars per share)	$ 21.36	$ 30.55
Forfeited shares ( in dollars per share)		24.10
Nonvested, balance at the end of the period (in dollars per share)	$ 27.22	$ 24.38	$ 27.22	$ 24.38	$ 24.38

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Equity Compensation (Detail 2) - shares	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Equity Compensation
Number of shares accrued in director's accounts	160,124	164,085
Shares available for issuance	656,737	685,996
Units accrued for service and dividends (in shares)	23,698	25,187
Units redeemed for common stock (in shares)	21,246	28,991

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Regulated Operating Expense (Details) - USD ($) $ in Thousands	3 Months Ended		12 Months Ended
	Mar. 31, 2016	Mar. 31, 2015	Mar. 31, 2016	Mar. 31, 2015
Regulated Operating Expense
Electric transmission and distribution expense	$ 6,836	$ 7,100	$ 28,629	$ 28,221
Natural gas transmission and distribution expense	706	677	2,727	2,365
Power operation expense (other than fuel)	4,053	5,317	16,999	17,415
Customer accounts and assistance expense	2,731	2,704	10,965	11,106
Employee pension expense	2,625	2,684	10,727	10,648
Employee healthcare expense	2,245	2,234	10,173	9,656
General office supplies and expense	4,339	2,834	15,944	13,666
Administrative and general expense	4,116	4,556	14,423	14,716
Allowance for uncollectible accounts	79	327	1,833	2,975
Miscellaneous expense	115	118	425	603
Total	$ 27,845	$ 28,551	$ 112,845	$ 111,371

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Segment Information (Details) - USD ($) $ in Thousands	3 Months Ended		12 Months Ended
	Mar. 31, 2016	Mar. 31, 2015	Mar. 31, 2016	Mar. 31, 2015	Dec. 31, 2015
Statement of Income Information, balance sheet information and capital expenditures of business segments
Operating Revenues	$ 151,315	$ 164,544	$ 592,344	$ 637,201
Depreciation and amortization	20,403	20,020	80,933	75,264
Federal and state income taxes	8,640	8,771	33,681	35,871
Operating income	23,243	24,713	94,578	95,225
Interest income	9	11	144	20
Interest expense	11,628	11,044	45,686	42,459
Income from AFUDC (debt and equity)	2,758	1,542	8,910	9,467
Net income	14,009	14,637	55,969	60,835
Capital Expenditures	34,449	53,555	157,417	226,347
Total assets	2,450,926		2,450,926		$ 2,446,645
Goodwill	39,492		39,492		39,492
Operating segments | Electric
Statement of Income Information, balance sheet information and capital expenditures of business segments
Operating Revenues	134,363	142,641	546,808	582,043
Depreciation and amortization	18,916	18,589	75,059	69,547
Federal and state income taxes	7,568	7,202	31,489	32,692
Operating income	20,507	21,214	87,165	86,176
Interest income	4	2	135	7
Interest expense	10,688	10,091	41,903	38,635
Income from AFUDC (debt and equity)	2,754	1,541	8,893	9,408
Net income	12,240	12,096	52,384	55,679
Capital Expenditures	33,167	52,263	150,016	218,696
Total assets	2,335,112		2,335,112		2,331,705
Operating segments | Gas
Statement of Income Information, balance sheet information and capital expenditures of business segments
Operating Revenues	15,113	19,818	36,997	47,051
Depreciation and amortization	996	972	3,947	3,822
Federal and state income taxes	799	1,126	473	1,519
Operating income	2,293	2,788	4,657	6,289
Interest income	10	12	35	25
Interest expense	969	965	3,871	3,863
Income from AFUDC (debt and equity)	4	1	17	59
Net income	1,326	1,822	791	2,457
Capital Expenditures	863	683	5,369	5,348
Total assets	129,987		129,987		127,359
Goodwill	39,492		39,492		39,492
Operating segments | Other
Statement of Income Information, balance sheet information and capital expenditures of business segments
Operating Revenues	2,184	2,430	9,918	9,437
Depreciation and amortization	491	459	1,927	1,895
Federal and state income taxes	273	443	1,719	1,660
Operating income	443	711	2,756	2,760
Interest income	24	9	62	27
Net income	443	719	2,794	2,699
Capital Expenditures	419	609	2,032	2,303
Total assets	38,417		38,417		38,299
Eliminations
Statement of Income Information, balance sheet information and capital expenditures of business segments
Operating Revenues	(345)	(345)	(1,379)	(1,330)
Interest income	(29)	(12)	(88)	(39)
Interest expense	(29)	$ (12)	(88)	$ (39)
Total assets	$ (52,590)		$ (52,590)		$ (50,718)

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Income Taxes (Details) - USD ($) $ in Thousands	3 Months Ended		12 Months Ended
	Mar. 31, 2016	Mar. 31, 2015	Mar. 31, 2016	Mar. 31, 2015	Dec. 31, 2014	Dec. 31, 2010
Income Taxes
Consolidated provision for income taxes	$ 8,640	$ 8,771	$ 33,681	$ 35,871
Consolidated effective federal and state income tax rates (as a percent)	38.10%	37.50%	37.60%	37.10%
Net operating loss					$ 74,100
Deferred tax assets					38,000
Deferred tax assets estimated to be utilized	$ 13,500		$ 13,500
Advanced coal investment tax credit						$ 17,700
Maximum tax credit utilized					9,000
Adjustment due to change in tax accounting method om deduction and capitalization of tangible property					29,000
Adjustment due to change in tax accounting method on deductibility of VEBA plan activity					$ 14,000

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Mergers and Acquisitions (Details) - USD ($)		3 Months Ended	12 Months Ended
	Feb. 09, 2016	Mar. 31, 2016	Dec. 31, 2016	Mar. 31, 2016
Mergers and Acquisitions
Termination fee	$ 53,000,000
Maximum period for extending regulatory approvals	6 months
Maximum period for exercising termination right	9 months
Transaction costs		$ 4,248,000		$ 4,499,000
Liberty Utilities (Central) Co
Mergers and Acquisitions
Right to receive in cash without interest	$ 34.00
Termination fee	$ 65,000,000
Forecast
Mergers and Acquisitions
Percentage payable of transaction costs			50.00%
Forecast | High end of range
Mergers and Acquisitions
Transaction costs			$ 17,000,000
Forecast | Low end of range
Mergers and Acquisitions
Transaction costs			$ 15,000,000