EMPIRE DISTRICT ELECTRIC CO - FORM 10-Q

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EX-32.B - EX-32.B - EMPIRE DISTRICT ELECTRIC CO	a16-11597_1ex32db.htm
EX-32.A - EX-32.A - EMPIRE DISTRICT ELECTRIC CO	a16-11597_1ex32da.htm
EX-31.B - EX-31.B - EMPIRE DISTRICT ELECTRIC CO	a16-11597_1ex31db.htm
EX-31.A - EX-31.A - EMPIRE DISTRICT ELECTRIC CO	a16-11597_1ex31da.htm
EX-12 - EX-12 - EMPIRE DISTRICT ELECTRIC CO	a16-11597_1ex12.htm

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended June 30, 2016 or

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

For the transition period from to .

Commission file number: 1-3368

THE EMPIRE DISTRICT ELECTRIC COMPANY

(Exact name of registrant as specified in its charter)

Kansas
(State of Incorporation)

44-0236370
(I.R.S. Employer Identification No.)

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

64801
(zip code)

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

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

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

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

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

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

As of July 29, 2016, 44,038,094 shares of common stock were outstanding.

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THE EMPIRE DISTRICT ELECTRIC COMPANY

INDEX

		PAGE
	Forward Looking Statements	3

Part I -	Financial Information:

Item 1.	Financial Statements:

	a. Consolidated Statements of Income	5

	b. Consolidated Balance Sheets	8

	c. Consolidated Statements of Cash Flows	10

	d. Notes to Consolidated Financial Statements	11

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	31

	Executive Summary	31

	Results of Operations	34

	Rate Matters	40

	Markets and Transmission	41

	Liquidity and Capital Resources	42

	Contractual Obligations	46

	Dividends	46

	Off-Balance Sheet Arrangements	46

	Critical Accounting Policies and Estimates	46

	Recently Issued Accounting Standards	46

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	46

Item 4.	Controls and Procedures	48

Part II-	Other Information:

Item 1.	Legal Proceedings	49

Item 1A.	Risk Factors	49

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	49

Item 6.	Exhibits	49

	Signatures	51

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FORWARD LOOKING STATEMENTS

Certain matters discussed in this quarterly report are “forward-looking statements” intended to qualify for the safe harbor from liability established by the Private Securities Litigation Reform Act of 1995. Such statements address or may address future plans, objectives, expectations and events or conditions concerning various matters such as 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 with Liberty Central, including, without limitation:

· the risk 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;

· 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;

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· 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 discussed in the proxy statement and other materials that Empire has filed 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.

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PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

	Three Months Ended
	June 30,
	2016			2015
	(000’s except per share amounts)
Operating revenues:
Electric	$	131,822		$	126,282
Gas	5,641			6,279
Other	1,857			1,996
	139,320			134,557
Operating revenue deductions:
Fuel and purchased power	37,505			39,153
Cost of natural gas sold and transported	1,478			2,041
Regulated operating expenses	27,485			27,669
Other operating expenses	854			789
Maintenance and repairs	12,712			15,583
Merger related expenses	4,192			—
Depreciation and amortization	20,817			20,127
Provision for income taxes	5,792			4,056
Other taxes	9,108			9,092
	119,943			118,510

Operating income	19,377			16,047
Other income and (deductions):
Allowance for equity funds used during construction	1,062			1,234
Interest income	44			129
Benefit for other income taxes	117			14
Other - non-operating expense, net	(361		)	(225		)
	862			1,152
Interest charges:
Long-term debt	11,298			10,752
Short-term debt	26			95
Allowance for borrowed funds used during construction	(616		)	(723		)
Other	306			305
	11,014			10,429

Net income	$	9,225		$	6,770

Weighted average number of common shares outstanding - basic	43,953			43,627

Weighted average number of common shares outstanding - diluted	44,006			43,712

Total earnings per weighted average share of common stock — basic	$	0.21		$	0.16

Total earnings per weighted average share of common stock — diluted	$	0.21		$	0.15

Dividends declared per share of common stock	$	0.26		$	0.26

See accompanying Notes to Consolidated Financial Statements.

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THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

	Six Months Ended
	June 30,
	2016			2015
	(000’s except per share amounts)
Operating revenues:
Electric	$	266,185		$	268,924
Gas	20,754			26,096
Other	3,696			4,081
	290,635			299,101
Operating revenue deductions:
Fuel and purchased power	75,345			88,131
Cost of natural gas sold and transported	9,039			13,464
Regulated operating expenses	55,329			56,219
Other operating expenses	1,815			1,594
Maintenance and repairs	22,931			25,850
Merger related expenses	8,440			—
Depreciation and amortization	41,221			40,147
Provision for income taxes	14,467			12,939
Other taxes	19,428			19,996
	248,015			258,340

Operating income	42,620			40,761
Other income and (deductions):
Allowance for equity funds used during construction	2,766			2,212
Interest income	53			140
Benefit for other income taxes	153			127
Other - non-operating expense, net	(769		)	(924		)
	2,203			1,555
Interest charges:
Long-term debt	22,596			21,503
Short-term debt	88			168
Allowance for borrowed funds used during construction	(1,669		)	(1,287		)
Other	574			525
	21,589			20,909

Net income	$	23,234		$	21,407

Weighted average number of common shares outstanding - basic	43,918			43,579

Weighted average number of common shares outstanding — diluted	43,963			43,669

Total earnings per weighted average share of common stock — basic and diluted	$	0.53		$	0.49

Dividends declared per share of common stock	$	0.52		$	0.52

See accompanying Notes to Consolidated Financial Statements.

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THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

	Twelve Months Ended
	June 30,
	2016			2015
	(000’s except per share amounts)
Operating revenues:
Electric	$	552,347		$	567,559
Gas	36,360			46,341
Other	8,400			8,076
	597,107			621,976
Operating revenue deductions:
Fuel and purchased power	157,075			193,273
Cost of natural gas sold and transported	15,076			22,767
Regulated operating expenses	112,661			111,430
Other operating expenses	3,530			3,083
Maintenance and repairs	45,603			50,975
Merger related expenses	8,440			—
Depreciation and amortization	81,624			77,234
Provision for income taxes	36,328			33,469
Other taxes	38,611			37,975
	498,948			530,206

Operating income	98,159			91,770
Other income and (deductions):
Allowance for equity funds used during construction	5,405			5,859
Interest income	58			147
Benefit for other income taxes	1,014			206
Other - non-operating expense, net	(3,274		)	(1,581		)
	3,203			4,631
Interest charges:
Long-term debt	44,895			41,929
Short-term debt	186			263
Allowance for borrowed funds used during construction	(3,226		)	(3,214		)
Other	1,083			1,012
	42,938			39,990

Net income	$	58,424		$	56,411

Weighted average number of common shares outstanding — basic	43,839			43,492
Weighted average number of common shares outstanding — diluted	43,866			43,579

Total earnings per weighted average share of common stock — basic	$	1.33		$	1.30
Total earnings per weighted average share of common stock — diluted	$	1.33		$	1.29
Dividends declared per share of common stock	$	1.04		$	1.035

See accompanying Notes to Consolidated Financial Statements.

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THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS (UNAUDITED)

	June 30, 2016		December 31, 2015
	($-000’s)
Assets
Plant and property, at original cost:
Electric	$	2,682,604	$	2,473,927
Gas	85,309		83,402
Other	44,988		44,263
Construction work in progress	26,365		183,689
	2,839,266		2,785,281
Accumulated depreciation and amortization	790,683		764,895
	2,048,583		2,020,386

Current assets:
Cash and cash equivalents	1,619		1,753
Restricted cash	4,727		4,726
Accounts receivable — trade, net of allowance $460 and $623, respectively	41,511		40,162
Accrued unbilled revenues	23,361		20,653
Accounts receivable — other	16,603		28,320
Fuel, materials and supplies	57,735		60,950
Prepaid expenses and other	8,378		8,835
Unrealized gain in fair value of derivative contracts	6,234		1,295
Regulatory assets	7,120		7,052
	167,288		173,746

Noncurrent assets and deferred charges:
Regulatory assets	209,682		209,708
Goodwill	39,492		39,492
Unrealized gain in fair value of derivative contracts	410		16
Other	3,180		3,297
	252,764		252,513
Total Assets	$	2,468,635	$	2,446,645

(Continued)

See accompanying Notes to Consolidated Financial Statements.

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THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS (UNAUDITED) (Continued)

	June 30, 2016		December 31, 2015
	($-000’s)
Capitalization and Liabilities
Common stock, $1 par value, 44,024,803 and 43,820,726 shares issued and outstanding, respectively	$	44,025	$	43,821
Capital in excess of par value	662,477		657,466
Retained earnings	101,821		101,443
Total common stockholders’ equity	808,323		802,730

Long-term debt (net of current portion):
Obligations under capital lease	3,418		3,580
First mortgage bonds and secured debt	725,155		724,838
Unsecured debt	100,964		100,935
Total long-term debt	829,537		829,353
Total long-term debt and common stockholders’ equity	1,637,860		1,632,083

Current liabilities:
Accounts payable and accrued liabilities	45,628		66,946
Current maturities of long-term debt	25,289		25,246
Short-term debt	30,500		25,000
Regulatory liabilities	12,290		8,615
Customer deposits	15,016		14,623
Interest accrued	7,642		7,348
Unrealized loss in fair value of derivative contracts	1,175		4,472
Taxes accrued	13,619		2,832
Other current liabilities	272		323
	151,431		155,405

Commitments and contingencies (Note 7)

Noncurrent liabilities and deferred credits:
Regulatory liabilities	142,017		132,457
Deferred income taxes	410,922		396,542
Unamortized investment tax credits	18,432		18,487
Pension and other postretirement benefit obligations	78,513		82,144
Unrealized loss in fair value of derivative contracts	2,676		3,696
Other	26,784		25,831
	679,344		659,157
Total Capitalization and Liabilities	$	2,468,635	$	2,446,645

See accompanying Notes to Consolidated Financial Statements.

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THE EMPIRE DISTRICT ELECTRIC COMPANYCONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

	Six Months Ended
	June 30,
	2016			2015
	($-000’s)
Operating activities:
Net income	$	23,234		$	21,407
Adjustments to reconcile net income to cash flows from operating activities:
Depreciation and amortization including regulatory items and other	40,815			45,698
Pension and other postretirement benefit costs, net of contributions	195			(15,109		)
Deferred income taxes and unamortized investment tax credit, net	14,314			9,337
Allowance for equity funds used during construction	(2,766		)	(2,212		)
Stock compensation expense	2,905			999
Non-cash (gain)/loss on derivatives	2,346			3,300
Other	84			—
Cash flows impacted by changes in:
Accounts receivable and accrued unbilled revenues	5,152			21,171
Fuel, materials and supplies	3,214			(301		)
Prepaid expenses, other current assets and deferred charges	(8,779		)	(351		)
Accounts payable and accrued liabilities	(20,078		)	(26,130		)
Interest, taxes accrued and customer deposits	11,474			10,832
Asset retirement obligations	(86		)	—
Other liabilities and other deferred credits	10,327			5,456

Net cash provided by operating activities	82,351			74,097

Investing activities:
Capital expenditures — regulated	(67,968		)	(106,295		)
Capital expenditures and other investments — non-regulated	(557		)	(950		)
Restricted cash	(1		)	—

Net cash used in investing activities	(68,526		)	(107,245		)

Financing activities:
Proceeds from issuance of common stock, net of issuance costs	3,551			2,878
Net short-term borrowings	5,500			53,000
Dividends	(22,856		)	(22,671		)
Other	(154		)	(172		)

Net cash provided by (used in) financing activities	(13,959		)	33,035

Net decrease in cash and cash equivalents	(134		)	(113		)

Cash and cash equivalents at beginning of period	1,753			2,105

Cash and cash equivalents at end of period	$	1,619		$	1,992

See accompanying Notes to Consolidated Financial Statements.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

Note 1 - Summary of Significant Accounting Policies

We operate our businesses as three segments: electric, gas and other. The Empire District Electric Company (EDE), a Kansas corporation organized in 1909, is an operating public utility engaged in the generation, purchase, transmission, distribution and sale of electricity in parts of Missouri, Kansas, Oklahoma and Arkansas. As part of our electric segment, we also provide water service to three towns in Missouri. The Empire District Gas Company (EDG) is our wholly-owned subsidiary which provides natural gas distribution to customers in 48 communities in northwest, north central and west central Missouri. Our other segment consists of our fiber optics business.

The accompanying interim financial statements do not include all disclosures included in the annual financial statements and therefore should be read in conjunction with the financial statements and notes thereto included in our Annual Report on Form 10-K for the fiscal year ended December 31, 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.

Note 2 - Recently Issued and Proposed Accounting Standards

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 $8.7 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 and $8.3 million in unamortized debt issuance costs being reclassified from deferred charges to long-term debt on the June 30, 2016 Consolidated Balance Sheet.

Revenue from contracts with customers: In June 2014, the FASB issued new guidance governing revenue recognition. Under the new guidance, an entity is required to recognize revenue in a pattern that depicts the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The new standard is effective for interim and annual reporting periods beginning after December 15, 2017. We are evaluating the impact of the adoption of this standard.

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

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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.

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.

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 sheets (in thousands).

Regulatory Assets and Liabilities

	June 30, 2016			December 31, 2015
Regulatory Assets:
Current:
Under recovered fuel costs	$	72		$	196
Current portion of long-term regulatory assets	7,048			6,856
Regulatory assets, current	7,120			7,052
Long-term:
Pension and other postretirement benefits(1)	104,328			108,273
Income taxes	48,546			48,613
Deferred construction accounting costs(2)	14,799			14,977
Unamortized loss on reacquired debt	9,394			9,731
Unsettled derivative losses — electric segment	4,525			7,775
System reliability — vegetation management	3,088			3,604
Storm costs	3,253			3,531
Asset retirement obligation	9,568			7,722
Customer programs	6,698			5,942
Missouri solar initiative(3)	10,336			3,504
Current portion of long-term regulatory assets	(7,048		)	(6,856		)
Other	2,195			2,892
Regulatory assets, long-term	209,682			209,708
Total Regulatory Assets	$	216,802		$	216,760

	June 30, 2016			December 31, 2015
Regulatory Liabilities:
Current:
Over recovered fuel costs	$	9,032		$	5,280
Current portion of long-term regulatory liabilities	3,258			3,335
Regulatory liabilities, current	12,290			8,615
Long-term:
Costs of removal(4)	98,132			94,193
SWPA payment for Ozark Beach lost generation	13,001			14,213
Income taxes	11,165			11,244
Deferred construction accounting costs — fuel(5)	7,613			7,690
Unamortized gain on interest rate derivative	2,946			3,031
Pension and other postretirement benefits	1,739			1,745
Over recovered fuel costs	8,950			2,300
System reliability — vegetation management	1,320			1,320
Current portion of long-term regulatory liabilities	(3,258		)	(3,335		)
Other	409			56
Regulatory liabilities, long-term	142,017			132,457
Total Regulatory Liabilities	$	154,307		$	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 748 solar rebate applications processed and internal costs as of June 30, 2016 (compared to 262 as of December 31, 2015), resulting in solar rebate-related costs totaling approximately $10.3 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 June 30, 2016 and December 31, 2015, we have recorded the following assets and liabilities representing the fair value of derivative financial instruments, (in thousands):

		June 30,		December 31,
ASSET DERIVATIVES		2016		2015
Hedging instruments	Balance Sheet Classification	Fair Value		Fair Value
Natural gas contracts, gas segment	Current assets	$	154	$	2
	Non-current assets and deferred charges - other	39		16

Natural gas contracts, electric segment	Current assets	1,454		—
	Non-current assets and deferred charges - other	371		—
Transmission congestion rights, electric segment	Current assets	4,626		1,293
Total derivatives assets		$	6,644	$	1,311

		June 30,		December 31,
LIABILITY DERIVATIVES		2016		2015
Hedging instruments	Balance Sheet Classification	Fair Value		Fair Value
Natural gas contracts, gas segment	Current liabilities	$	—	$	282
	Non-current liabilities and deferred credits	—		66

Natural gas contracts, electric segment	Current liabilities	1,175		4,190
	Non-current liabilities and deferred credits	2,676		3,630
Total derivatives liabilities		$	3,851	$	8,168

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Electric Segment

At June 30, 2016, approximately $0.3 million of unrealized net gains are applicable to natural gas financial instruments which will settle within the next twelve months.

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

Non-Designated Hedging Instruments - Due to	Balance Sheet Classification of	Amount of Gain / (Loss) Recognized on Balance Sheet
Regulatory Accounting	Gain / (Loss) on	Three Months Ended				Six Months Ended					Twelve Months Ended
Electric Segment	Derivative	2016		2015		2016		2015			2016			2015
Commodity contracts	Regulatory (assets)/liabilities	$	5,091	$	321	$	3,383	$	(2,219	)	$	(1,252	)	$	(11,157	)

Transmission congestion rights	Regulatory (assets)/liabilities	5,418		3,520		5,540		4,625			5,885			5,931
Total Electric Segment		$	10,509	$	3,841	$	8,923	$	2,406		$	4,633		$	(5,226	)

Non-Designated Hedging Instruments - Due to	Statement of Income Classification of	Amount of Gain / (Loss) Recognized in Income
Regulatory Accounting	Gain / (Loss) on	Three Months Ended					Six Months Ended						Twelve Months Ended
Electric Segment	Derivative	2016		2015			2016			2015			2016			2015
Commodity contracts	Fuel and purchased power expense	$	155	$	(855	)	$	(1,543	)	$	(2,277	)	$	(7,381	)	$	(4,850	)

Transmission congestion rights	Fuel and purchased power expense	1,547		1,875			2,343			5,313			4,498			11,197
Total Electric Segment		$	1,702	$	1,020		$	800		$	3,036		$	(2,883	)	$	6,347

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 June 30, 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	63	%	1,903,017	3,720,000	$	3.48	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	%	0	1,460,000	$	2.96	20%
2020	—		—	—	—		10%

At June 30, 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
2016-17	12,100	$	4,626

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Gas Segment

We attempt to mitigate our natural gas price risk for our gas segment by a combination of (1) injecting natural gas into storage during the off-heating season months, (2) purchasing physical forward contracts and (3) purchasing financial derivative contracts. We target to have 95% of our storage capacity full by November 1 for the upcoming winter heating season. As the winter progresses, gas is withdrawn from storage to serve our customers. As of June 30, 2016, we had 1.6 million Dths in storage on the three pipelines that serve our customers. This represents 79% 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 June 30, 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	—	1,605	60	%
Nov. 2017 - Mar. 2018	Up to 50%	280	—	—	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 June 30, (in thousands).

Non-Designated Hedging Instruments Due to Regulatory	Balance Sheet Classification of Gain / (Loss) on	Amount of Gain/(Loss) Recognized on Balance Sheet
Accounting - Gas Segment	Derivative	Three Months Ended				Six Months Ended				Twelve Months Ended
		2016		2015		2016		2015		2016			2015
Commodity contracts	Regulatory (assets)/liabilities	$	240	$	203	$	172	$	186	$	(461	)	$	(434	)

Total - Gas Segment		$	240	$	203	$	172	$	186	$	(461	)	$	(434	)

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 June 30, 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)	June 30, 2016		December 31, 2015
Margin deposit assets	$	4.6	$	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

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agreements: (1) the International Swaps and Derivatives Association Agreement, a standardized financial natural gas and electric contract; and (2) the North American Energy Standards Board Inc. Agreement, a standardized contract for the purchase and sale of natural gas. These master trading and netting agreements allow the counterparties to net settle sale and purchase transactions. Collateral requirements are calculated at the master trading and netting agreement level by the counterparty.

As shown above, our asset and liability commodity contract derivatives are reported at gross on the balance sheet. ASC guidance permits companies to offset fair value amounts recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a liability) against fair value amounts recognized for derivative instruments that are executed with the same counterparty under the same master netting arrangement. For the periods ended June 30, 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 June 30, 2016 and December 31, 2015.

	Fair Value Measurements at Reporting Date Using
				Quoted Prices in Active			Significant Other		Significant
				Markets for Identical			Observable		Unobservable
($ in 000’s)	Assets/(Liabilities)			Assets/(Liabilities)			Inputs		Inputs
Description	at Fair Value			(Level 1)			(Level 2)		(Level 3)
				June 30, 2016
Derivative assets	$	6,644		$	2,018		$	4,626	$	—
Derivative liabilities	$	(3,851	)	$	(3,851	)	$	—	$	—

				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 June 30, 2016 and December 31, 2015 was $851 million. The fair market value at June 30, 2016 was approximately $897 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 June 30, 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 June 30, 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 June 30, 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 June 30, 2016; however, $30.5 million was used to back up our outstanding commercial paper.

Note 7— Commitments and Contingencies

Legal Proceedings

We are a party to various claims and legal proceedings arising out of the normal course of our business. We regularly analyze this information, and provide accruals for any liabilities, in accordance with the guidelines presented in the ASC on accounting for contingencies. In 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 shareholder filed an amended complaint on April 15, 2016. 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.

On June 7, 2016, following arm’s length negotiations, Empire and other defendants entered into a Memorandum of Understanding (MOU) providing for the settlement, subject to court approval, of all claims asserted in the complaint against all defendants. In connection with the MOU, Empire agreed to make additional disclosures related to the Merger in the proxy statement (which were made on June 8, 2016). Empire and the other defendants that entered into the MOU did so solely to avoid

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the costs, risks and uncertainties inherent in litigation and without admitting any liability or wrongdoing, and vigorously denied, and continue to vigorously deny, that they committed any violation of law or engaged in any wrongful acts alleged in the complaint.

The parties to the MOU have agreed to attempt in good faith to finalize and execute a stipulation of settlement and to present the stipulation of settlement to the Court for final approval. The stipulation of settlement will be subject to customary conditions, including approval by the Court. The stipulation of settlement will provide for, among other things, certification of the alleged class as a non-opt-out class action and an award of plaintiff’s reasonable attorneys’ fees and expenses. The stipulation of settlement will also provide for the release of any and all claims arising out of or relating to the Merger. The settlement is subject to final Court approval following notice to the class members. There can be no assurance that the settling parties will ultimately enter into a stipulation of settlement or that the Court will approve the settlement. In such event, or if the Merger is not consummated for any reason, the proposed settlement will be null and void and of no force and effect.

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 June 30, 2016 (in millions).

	Firm physical gas and transportation contracts		Coal and coal transportation contracts

July 1, 2016 through December 31, 2016	$	14.3	$	8.2
January 1, 2017 through December 31, 2018	37.4		27.3
January 1, 2019 through December 31, 2020	28.8		10.7
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 June 30, 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 $272.6 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, majority 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

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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 June 30, 2016 were $167.5 million for the project to date, excluding AFUDC. Final costs are estimated to range from $167.5 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 June 30, 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 Missouri Public Service Commission (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), were the drivers behind our 2013 Compliance Plan and its implementation schedule. Compliance costs we have incurred associated with the MATS, CAIR and CSAPR regulations are being recovered in our rates and we anticipate any future costs to continue to be recoverable in our rates.

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

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Regulations

Air Emissions - NOx and SO2

ACID RAIN

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

Water Discharges

MATS: As noted above, the completion of our Compliance Plan puts us in compliance with 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. MATS has remained in place, and a final supplemental finding issued on April 14, 2016 completes the EPA’s response to the Supreme Court’s decision. 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. Presentation of oral arguments before a three-judge panel scheduled for early June has been changed as defenders and challengers of the climate rule will make their case before all participating judges on September 27, 2016.

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 EPA continues to work on the CPP and released a proposed rule for the Clean Energy Incentive Program (CEIP) design guidelines on June 16, 2016. 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 will begin to 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 affected 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). Compliance with both the CCR and ELG rules will result in

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the need to close our existing ash impoundment, construct a new utility waste landfill and convert the existing bottom ash handling from a wet to a dry system at our Asbury Power Plant. 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.

At this time, we anticipate compliance costs to be approximately $15 million. The landfill construction, bottom ash conversion and impoundment closure are anticipated to be complete in early 2019, and we expect compliance costs to be recoverable in our rates.

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 Missouri 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. We expect solar rebates to be sufficient to allow compliance with the current 2% requirement. As of June 30, 2016, we had processed 748 solar rebate applications resulting in solar rebate-related costs totaling approximately $10.3 million under the new tariff. We have recorded the $10.3 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 adopted that altered the Kansas renewable portfolio standard (RPS), ending all mandatory requirements in 2015. The former 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 meeting the voluntary goal as a result of purchased power agreements with Cloud County Windfarm, LLC and Elk River Windfarm, LLC.

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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 June 30,
	Pension Benefits						SERP						OPEB
	2016			2015			2016			2015			2016			2015
Service cost	$	1,949		$	1,883		$	45		$	43		$	814		$	920
Interest cost	2,633			2,503			108			92			1,157			1,163
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			257			681
Net periodic benefit cost	$	3,066		$	3,184		$	289		$	264		$	601		$	1,199

	Six months ended June 30,
	Pension Benefits						SERP						OPEB
	2016			2015			2016			2015			2016			2015
Service cost	$	3,899		$	3,765		$	91		$	85		$	1,627		$	1,840
Interest cost	5,266			5,006			215			184			2,313			2,327
Expected return on plan assets	(6,931		)	(6,779		)	—			—			(2,748		)	(2,625		)
Amortization of prior service cost (1)	(315		)	(315		)	(7		)	(21		)	(506		)	(506		)
Amortization of net actuarial loss (1)	4,213			4,690			278			280			515			1,363
Net periodic benefit cost	$	6,132		$	6,367		$	577		$	528		$	1,201		$	2,399

	Twelve months ended June 30,
	Pension Benefits						SERP						OPEB
	2016			2015			2016			2015			2016			2015
Service cost	$	7,575		$	6,978		$	164		$	180		$	3,500		$	3,227
Interest cost	10,538			10,359			413			399			4,656			4,525
Expected return on plan assets	(13,719		)	(13,241		)	—			—			(5,320		)	(5,032		)
Amortization of prior service cost (1)	(630		)	(106		)	(28		)	(26		)	(1,011		)	(1,011		)
Amortization of net actuarial loss (1)	9,556			8,003			595			574			1,901			1,873
Net periodic benefit cost	$	13,320		$	11,993		$	1,144		$	1,127		$	3,726		$	3,582

(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, of which we have made contributions of approximately $6.1 million as of June 30, 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, of which we have made contributions of approximately $1.2 million as of June 30, 2016. The actual minimum funding requirements for both pension and OPEB will be determined based on the results of the actuarial valuations.

Employee Stock Purchase Plan

Our Employee Stock Purchase Plan (ESPP) permits the grant to eligible employees of options to purchase common stock at 90% of the lower of market value at date of grant or at date of exercise. The lookback feature of this plan is valued at 90% of the Black-Scholes methodology plus 10% of the maximum subscription price. As of June 30, 2016, there were 707,735 shares available for issuance in this plan.

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	2016		2015
Subscriptions outstanding at June 30	25,407		59,529
Maximum subscription price(1)	$	30.29	$	21.43
Shares of stock issued	56,908		56,193
Stock issuance price	$	21.09	$	21.01

(1) Stock will be issued on the closing date of the purchase period, which runs from June 1, 2016 to May 31, 2017.

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

	2016	2015
Fair value of grants at June 30	$ 6.11	$ 3.58
Risk-free interest rate	0.70%	0.26%
Expected dividend yield	3.10%	4.40%
Expected volatility	27.00%	21.00%
Expected life in months	12	12
Grant Date	6/1/16	6/1/15

Pursuant to the Merger Agreement, the right of any employee to continue participation in the ESPP and any purchase period under the ESPP then in effect shall terminate immediately prior to the effective time of the Merger. Payment of all remaining, unused amounts credited to each participant’s account, together with interest as provided in the ESPP, shall be made to the applicable participant as promptly as practicable following the effective time.

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 $1.9 million as of June 30, 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 June 30 (in thousands):

	Three Months Ended				Six Months Ended				Twelve Months Ended
	2016		2015		2016		2015		2016		2015
Compensation Expense	$	834	$	319	$	2,910	$	1,061	$	6,128	$	2,882
Tax Benefit Recognized	303		108		1,080		379		2,277		1,048

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,

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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 June 30	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 June 30, 2016 and 2015 and changes during the six months ended June 30, 2016 and 2015 were as follows:

	2016				2015
	Number		Weighted		Number		Weighted
	of		Average Grant		of		Average Grant
	shares		Date Fair Value		shares		Date Fair Value
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 June 30,	66,788		$	27.22	69,021		$	24.38

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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 June 30, 2016 and 2015 are shown in the table below:

	2016	2015
Shares accrued to directors’ accounts	161,361	162,058
Shares available for issuance	656,737	685,996

Units accrued for service and dividends as well as units redeemed for common stock during the six months ended June 30, 2016 and 2015 are shown in the table below:

	2016	2015
Units accrued for service and dividends	24,935	26,965
Units redeemed for common stock	21,246	28,991

Note 10- Regulated Operating Expenses

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

	Three Months Ended		Three Months Ended		Six Months Ended		Six Months Ended		Twelve Months Ended		Twelve Months Ended
	2016		2015		2016		2015		2016		2015
Electric transmission and distribution expense	$	6,626	$	7,414	$	13,462	$	14,514	$	27,842	$	28,757
Natural gas transmission and distribution expense	617		728		1,323		1,405		2,617		2,535
Power operation expense (other than fuel)	3,986		4,238		8,039		9,555		16,746		17,633
Customer accounts and assistance expense	2,809		2,790		5,540		5,493		10,984		11,013
Employee pension expense (1)	2,644		2,718		5,269		5,401		10,654		10,764
Employee healthcare plan (1)	2,437		2,384		4,682		4,618		10,226		9,433
General office supplies and expense	3,938		2,847		8,277		5,680		17,035		13,328
Administrative and general expense	3,542		3,440		7,658		7,997		14,524		14,718
Allowance for uncollectible accounts	800		1,018		879		1,345		1,614		2,664
Miscellaneous expense	86		92		200		211		419		585
Total	$	27,485	$	27,669	$	55,329	$	56,219	$	112,661	$	111,430

(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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Note 11— Segment Information

The tables below present statement of income information, balance sheet information and capital expenditures of our business segments. Merger related expenses are reflected below in the electric segment operating income.

	For the three months ended June 30, 2016
($-000’s)	Electric		Gas			Other		Eliminations			Total
Statement of Income Information
Revenues	$	131,822	$	5,641		$	2,202	$	(345	)	$	139,320
Depreciation and amortization	19,319		1,005			493		—			20,817
Federal and state income taxes	5,659		(322		)	338		—			5,675
Operating income	18,438		435			504		—			19,377
Interest income	40		14			25		(35		)	44
Interest expense	10,698		967			—		(35		)	11,630
Income from AFUDC (debt and equity)	1,676		2			—		—			1,678
Net income	9,207		(530		)	548		—			9,225

Capital Expenditures	$	29,483	$	1,141		$	159	—			$	30,783

	For the three months ended June 30, 2015
($-000’s)	Electric		Gas			Other		Eliminations			Total
Statement of Income Information
Revenues	$	126,282	$	6,279		$	2,341	$	(345	)	$	134,557
Depreciation and amortization	18,690		976			461		—			20,127
Federal and state income taxes	3,957		(332		)	417		—			4,042
Operating income	14,954		428			665		—			16,047
Interest income	124		16			12		(23		)	129
Interest expense	10,210		965			—		(23		)	11,152
Income from AFUDC (debt and equity)	1,955		2			—		—			1,957
Net income	6,627		(534		)	677		—			6,770

Capital Expenditures	$	45,847	$	987		$	743	—			$	47,577

	For the six months ended June 30, 2016
($-000’s)	Electric		Gas		Other		Eliminations			Total
Statement of Income Information
Revenues	$	266,185	$	20,754	$	4,386	$	(690	)	$	290,635
Depreciation and amortization	38,235		2,001		985		—			41,221
Federal and state income taxes	13,227		477		610		—			14,314
Operating income	38,945		2,728		947		—			42,620
Interest income	43		25		49		(64		)	53
Interest expense	21,386		1,936		—		(64		)	23,258
Income from AFUDC (debt and equity)	4,429		6		—		—			4,435
Net income	21,447		796		991		—			23,234

Capital Expenditures	$	62,650	$	2,003	$	579	—			$	65,232

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	For the six months ended June 30, 2015
($-000’s)	Electric		Gas		Other		Eliminations			Total
Statement of Income Information
Revenues	$	268,924	$	26,096	$	4,771	$	(690	)	$	299,101
Depreciation and amortization	37,279		1,948		920		—			40,147
Federal and state income taxes	11,159		794		859		—			12,812
Operating income	36,168		3,216		1,377		—			40,761
Interest income	126		28		21		(35		)	140
Interest expense	20,301		1,930		—		(35		)	22,196
Income from AFUDC (debt and equity)	3,496		3		—		—			3,499
Net income	18,723		1,288		1,396		—			21,407

Capital Expenditures	$	98,110	$	1,670	$	1,354	—			$	101,134

	For the twelve months ended June 30, 2016
($-000’s)	Electric		Gas		Other		Eliminations			Total
Statement of Income Information
Revenues	$	552,347	$	36,360	$	9,780	$	(1,380	)	$	597,107
Depreciation and amortization	75,689		3,975		1,960		—			81,624
Federal and state income taxes	33,192		483		1,639		—			35,314
Operating income	90,900		4,665		2,594		—			98,159
Interest income	50		33		75		(100		)	58
Interest expense	42,391		3,873		—		(100		)	46,164
Income from AFUDC (debt and equity)	8,614		17		—		—			8,631
Net income	54,963		796		2,665		—			58,424

Capital Expenditures	$	133,652	$	5,523	$	1,448	—			$	140,623

	For the twelve months ended June 30, 2015
($-000’s)	Electric		Gas		Other		Eliminations			Total
Statement of Income Information
Revenues	$	567,559	$	46,341	$	9,431	$	(1,355	)	$	621,976
Depreciation and amortization	71,446		3,885		1,903		—			77,234
Federal and state income taxes	30,318		1,277		1,668		—			33,263
Operating income	82,945		6,093		2,732		—			91,770
Interest income	131		34		35		(53		)	147
Interest expense	39,391		3,866		—		(53		)	43,204
Income from AFUDC (debt and equity)	9,062		11		—		—			9,073
Net Income	51,480		2,218		2,713		—			56,411

Capital Expenditures	$	219,362	$	5,051	$	2,752	—			$	227,165

	As of June 30, 2016
($-000’s)	Electric		Gas(1)		Other		Eliminations			Total
Balance Sheet Information
Total assets	$	2,355,251	$	126,037	$	38,884	$	(51,537	)	$	2,468,635

(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 June 30,:

	Three Months Ended						Six-Months Ended						Twelve Months Ended
	2016			2015			2016			2015			2016			2015
Consolidated provision for income taxes	$	5.7		$	4.0		$	14.3		$	12.8		$	35.3		$	33.3
Consolidated effective federal and state income tax rates	38.1		%	37.4		%	38.1		%	37.4		%	37.7		%	37.1		%

The effective income tax rate for the three, six and twelve month periods ended June 30, 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 June 30, 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. We also anticipate incurring a $19.4 million NOL in 2016 due to bonus depreciation on our recently completed Riverton Combined Cycle Plant project. As of June 30, 2016, we estimate there are $16.5 million of tax-affected 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.

Note 13 — Mergers and Acquisitions

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

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 (HSR Act)

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waiting period and receipt of all required regulatory approvals and consents, including from the Federal Energy Regulatory Commission (FERC), the Federal Communications Commission FCC), the Arkansas Public Service Commission (APSC), the Kansas Corporation Commission (KCC), the Missouri Public Service Commission (MPSC), the Oklahoma Corporation Commission (OCC) and the Committee on Foreign Investment in the United States (CFIUS), 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 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.

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. On May 6, 2016, we received an order from the FERC authorizing the Merger. We received an order on May 12, 2016 from the OCC approving the Merger.

On June 29, 2016, we filed a joint motion with the APSC to approve a Stipulation and Settlement Agreement in the matter of the joint application for approval of the Merger filed March 16, 2016. Approval of the agreement is pending before the APSC.

On July 20, 2016, we filed rebuttal testimony with the MPSC and non-unanimous stipulation and agreements were filed with several interveners. On August 4, 2016, we filed a non-unanimous stipulation and agreement with the staff of the MPSC. Position statements are due August 18, 2016 and evidentiary hearings are scheduled for August 29-31, 2016. Although there is no statutory time frame required, we would expect an order in Missouri before the end of the year.

The first settlement discussion took place in Kansas on July 15, 2016. Staff and intervener testimony is due September 29, 2016, and evidentiary hearings are scheduled to take place November 29-December 1, 2016. A commission order is due in Kansas on January 10, 2017.

On June 16, 2016, Empire’s shareholders voted to approve the merger.

On June 29, 2016, we and Algonquin filed a joint notice with CFIUS and we and Algonquin each filed notification with the Federal Trade Commission and U.S. Department of Justice under the HSR Act. The 30-day waiting period under the HSR Act expired on July 29, 2016 without receiving a request for additional information.

In connection with entering into the Merger Agreement, Empire has incurred approximately $8.4 million of transaction costs as of June 30, 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).

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

EXECUTIVE SUMMARY

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

During the twelve months ended June 30, 2016, our gross operating revenues were derived as follows:

Electric segment sales*	92.5	%
Gas segment sales	6.1
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.

Shareholder Lawsuit: 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. On June 7, 2016, following arm’s length negotiations, Empire and other defendants entered into a Memorandum of Understanding (MOU) providing for the settlement, subject to court approval, of all claims asserted in the complaint against all defendants. In connection with the MOU, Empire agreed to make additional disclosures related to the Merger in the proxy statement (which were made on June 8, 2016). Empire and the other defendants that entered into the MOU did so solely to avoid the costs, risks and uncertainties inherent in litigation and without admitting any liability or wrongdoing, and vigorously denied, and continue to vigorously deny, that they committed any violation of law or engaged in any wrongful acts alleged in the complaint. The parties to the MOU have agreed to attempt in good faith to finalize and execute a stipulation of settlement and to present the stipulation of settlement to the Court for final approval. The stipulation

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of settlement will be subject to customary conditions, including approval by the Court. The stipulation of settlement will provide for, among other things, certification of the alleged class as a non-opt-out class action and an award of plaintiff’s reasonable attorneys’ fees and expenses. The stipulation of settlement will also provide for the release of any and all claims arising out of or relating to the Merger. The settlement is subject to final Court approval following notice to the class members. There can be no assurance that the settling parties will ultimately enter into a stipulation of settlement or that the Court will approve the settlement. In such event, or if the Merger is not consummated for any reason, the proposed settlement will be null and void and of no force and effect. See Note 7 of “Notes to Consolidated Financial Statements (Unaudited).”

Merger Approval Status: 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. On May 6, 2016, we received an order from the FERC authorizing the Merger. We received an order on May 12, 2016 from the Oklahoma Corporation Commission approving the Merger. On June 29, 2016, we filed a joint motion with the Arkansas Public Service Commission (APSC) to approve a Stipulation and Settlement Agreement in the matter of the joint application for approval of the Merger filed March 16, 2016. Approval of the agreement is pending before the APSC.

On June 16, 2016, Empire’s shareholders voted to approve the merger.

Earnings

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

	Three Months Ended				Six Months Ended				Twelve Months Ended
	2016		2015		2016		2015		2016		2015
Basic earnings per weighted average share of common stock	$	0.21	$	0.16	$	0.53	$	0.49	$	1.33	$	1.30
Diluted earnings per weighted average share of common stock	$	0.21	$	0.15	$	0.53	$	0.49	$	1.33	$	1.29

Electric segment gross margin increased during all periods ended June 30, 2016 compared to 2015, reflecting increased electric rates for our Missouri customers effective July 26, 2015.

Electric earnings for the three months ended June 30, 2016 were positively impacted by the Missouri rate increase mentioned above as well as warmer weather and decreased maintenance expenses as compared to the same period in 2015. The impact of increased depreciation and interest expense negatively impacted earnings. Also negatively impacting earnings were approximately $4.2 million of merger related expenses during the three months ended June 30, 2016.

Electric earnings for the six months ended June 30, 2016 were positively impacted by the Missouri rate increase and decreases in regulated operating and maintenance expenses. Electric and gas earnings for this period were negatively impacted by milder weather in the first quarter of 2016 as compared to the same period last year. Electric earnings were also negatively impacted by increased depreciation expense and interest expense and approximately $8.4 million of merger related expenses.

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Electric earnings for the twelve months ended June 30, 2016 were positively impacted by the Missouri rate increase and decreased maintenance expense. Electric and gas earnings for this period were 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 earnings were also negatively impacted by increased regulated operating expense, property taxes, depreciation expense, interest expense, reduced AFUDC and approximately $8.4 million of merger related expenses.

The table below sets forth a reconciliation of basic and diluted earnings per share (EPS) between the three months, six months and twelve months ended June 30, 2015 and June 30, 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 June 30.

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

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			Six Months Ended			Twelve Months Ended
Earnings Per Share — 2015	$	0.16		$	0.49		$	1.30

Gross Margins
Electric segment	$	0.10		$	0.14		$	0.30
Gas segment	0.00			(0.02		)	(0.03		)
Other segment	0.00			0.00			0.00
Total Gross Margin	0.10			0.12			0.27

Operating — electric segment	0.00			0.01			(0.02		)
Operating —gas segment	0.00			0.00			0.00
Operating —operating segment	0.00			0.00			(0.01		)
Maintenance and repairs	0.04			0.04			0.08
Merger related expenses	(0.06		)	(0.12		)	(0.12		)
Depreciation and amortization	(0.01		)	(0.01		)	(0.06		)
Other taxes	0.00			0.01			(0.01		)
AFUDC	0.00			0.01			(0.01		)
Change in effective income tax rates	0.00			(0.01		)	(0.01		)
Interest charges	(0.01		)	(0.01		)	(0.04		)
Other income and deductions	(0.01		)	0.00			(0.03		)
Dilutive effect of additional shares issued	0.00			0.00			(0.01		)
Earnings Per Share — 2016	$	0.21		$	0.53		$	1.33

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Recent Activities

Regulatory Matters

On October 16, 2015, we filed a request with the Missouri Public Service Commission (MPSC) for changes in rates for our Missouri electric customers, seeking an annual increase in total revenue of approximately $33.4 million, or approximately 7.3%. We made a corresponding filing with the Oklahoma Corporation Commission (OCC) for adoption of Missouri proposed rates for our Oklahoma customers under an administrative ruling providing rate reciprocity which took effect in August 2015.

On June 21, 2016, we announced we had filed a Unanimous Stipulation and Agreement (Agreement) with the MPSC, which, if approved, allows an annual increase in base revenues of approximately $20.4 million, or 4.46%. Base revenues established by the agreement are lower than the originally requested level of $33.4 million due primarily to lower fuel and purchased power costs than those built into current customer rates. The offsetting effect of reduced revenues and costs results in little impact to gross margin. If approved, new rates are expected to become effective in mid-September 2016. The most significant factor driving the rate request was the cost associated with the conversion of the Riverton Unit 12 natural gas combustion turbine to combined cycle operation. The Agreement calls for the Fuel Adjustment Charge to remain in effect. In addition, a tracking mechanism for non-labor operating and maintenance expenses for the Riverton 12 Combined Cycle Unit will continue and tracking of pension and other post-employment benefit expenses will continue.

On July 1, 2016, we filed a Notice of Intended Case Filing with the Kansas Corporation Commission of our intentions to file an electric rate case in Kansas on or after August 1, 2016.

On July 21, 2016, we filed a request with the Arkansas Public Service Commission to implement a cost recovery rider for the conversion of the existing Riverton Unit 12 to combined cycle operation.

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 “Rate Matters” below for more information.

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).”

RESULTS OF OPERATIONS

The following discussion analyzes significant changes in the results of operations for the three month, six month and twelve month periods ended June 30, 2016, compared to the same periods ended June 30, 2015.

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

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	Three Months Ended						Six Months Ended				Twelve Months Ended
	2016			2015			2016		2015		2016		2015

Electric	$	9.2		$	6.6		$	21.4	$	18.7	$	55.0	$	51.5
Gas	(0.5		)	(0.5		)	0.8		1.3		0.8		2.2
Other	0.5			0.7			1.0		1.4		2.6		2.7
Net income	$	9.2		$	6.8		$	23.2	$	21.4	$	58.4	$	56.4

Electric Segment

Electric operating revenues comprised approximately 94.6% of our total operating revenues during the second 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 June 30, were as follows (in millions):

	kWh Sales
	3 Months	3 Months			6 Months	6 Months			12 Months	12 Months
	Ended	Ended	%		Ended	Ended	%		Ended	Ended	%
Customer Class	2016	2015	Change(1)		2016	2015	Change(1)		2016	2015	Change(1)
Residential	364.6	346.7	5.2	%	872.4	936.6	(6.9	)%	1,772.0	1,875.7	(5.5	)%
Commercial	393.8	394.0	(0.1	)	753.8	771.2	(2.3	)	1,560.0	1,584.6	(1.6	)
Industrial	277.7	271.7	2.2		525.5	517.4	1.6		1,072.6	1,050.2	2.1
Wholesale on-system	80.4	80.5	(0.0	)	159.4	162.1	(1.7	)	328.1	333.8	(1.7	)
Other(2)	30.9	30.2	2.1		64.9	64.6	0.5		131.4	127.3	3.2
Total on-system sales	1,147.4	1,123.1	2.2		2,376.0	2,451.9	(3.1	)	4,864.1	4,971.6	(2.2	)

(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 increased 2.2% during the quarter ended June 30, 2016 mainly due to warmer weather as compared to the same period in 2015. KWh sales for our residential customers increased 5.2% mainly due to the warmer weather. Commercial sales were flat. Industrial sales increased 2.2% mainly due to increased usage.

KWh sales for our on-system customers decreased 3.1% during the six months ended June 30, 2016, as compared to the same period in 2015, primarily due to decreased demand resulting from milder weather in the first quarter of 2016 as compared to the same period in 2015. Residential kWh sales decreased 6.9% mainly due to the milder weather. Commercial kWh sales decreased 2.3%. Industrial sales increased 1.6% mainly due to increased usage.

KWh sales for our on-system customers decreased 2.2% during the twelve months ended June 30, 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 and commercial kWh sales decreased primarily due to the milder weather during the twelve months ended June 30, 2016. Industrial sales increased 2.1% 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 $7.2 million, $10.0 million and $21.0 million during the three month, six month and twelve month periods ended June 30, 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

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expenditures to the fuel and purchased power expense shown on our statements of income) for the applicable periods ended June 30, were as follows (dollars in millions):

Electric Segment Operating Revenues and Gross Margin

	3 Months			3 Months					6 Months			6 Months					12 Months			12 Months
	Ended			Ended			%		Ended			Ended			%		Ended			Ended			%
Customer Class	2016			2015			Change(1)		2016			2015			Change(1)		2016			2015			Change(1)
Residential	$	48.6		$	45.2		7.7	%	$	110.7		$	113.2		(2.2	)%	$	228.1		$	230.4		(1.0	)%
Commercial	42.8			43.2			(0.9	)	80.6			82.5			(2.3	)	169.8			172.6			(1.6	)
Industrial	22.0			22.4			(1.8	)	41.1			41.4			(0.7	)	87.9			86.7			1.3
Wholesale on-system	4.7			4.7			0.5		9.2			8.2			11.8		19.0			19.7			(3.5	)
Other(2)	3.7			3.7			(0.6	)	7.6			7.6			(0.3	)	15.7			15.3			2.8
Total on-system revenues	$	121.8		$	119.2		2.2		$	249.2		$	252.9		(1.5	)	$	520.5		$	524.7		(0.8	)
Off-system wholesale(3)	—			—					—			—					—			0.1			(100.0	)
SPP IM net revenues(3)	6.3			3.4			85.2		9.3			8.1			15.7		16.3			27.2			(40.0	)
Total revenues from kWh sales	128.1			122.6			4.5		258.5			261.0			(0.9	)	536.8			552.0			(2.7	)
Miscellaneous revenues(4)	3.2			3.2			0.1		6.7			6.9			(4.0	)	13.5			13.5			(0.5	)
Total electric operating revenues	$	131.3		$	125.8		4.4		$	265.2		$	267.9		(1.0	)	$	550.3		$	565.5		(2.7	)
Water revenues	0.5			0.5			(0.2	)	1.0			1.0			0.4		2.0			2.1			0.7
Total electric segment operating revenues	$	131.8		$	126.3		4.4		$	266.2		$	268.9		(1.0	)	$	552.3		$	567.6		(2.7	)
Actual fuel and purchased power expenditures(3)	$	36.0		$	31.7		13.3		$	68.5		$	69.7		(1.7	)	$	139.8		$	143.8		(2.8	)
SPP IM net purchases(3)	(0.5		)	5.3			>(100.0)		3.7			11.6			(68.3	)	14.7			41.5			(64.6	)
Net fuel recovery and deferral	3.3			3.0			10.3		5.0			8.2			(38.1	)	5.7			9.7			(40.5	)
SWPA amortization(5)	(0.6		)	(0.6		)	(0.1	)	(1.2		)	(1.3		)	4.0		(2.5		)	(2.5		)	2.5
Unrealized (gain)/loss on derivatives	(0.7		)	(0.2		)	>(100.0)		(0.6		)	0.0			>(100.0)		(0.7		)	0.8			>(100.0)
Total fuel and purchased power expense per income statement	$	37.5		$	39.2		(4.2	)	$	75.4		$	88.1		(14.5	)	$	157.0		$	193.3		(18.7	)
Total Gross Margin	$	94.3		$	87.1		8.2		$	190.8		$	180.8		5.6		$	395.3		$	374.3		5.6

(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. 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.

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

(5) Missouri ten year amortization of the $26.6 million payment received from the Southwest Power Administration (SWPA) in September, 2010, of which $9.5 million of the Missouri portion remains to be amortized as of June 30, 2016.

Revenues for our on-system customers increased $2.7 million during the second quarter of 2016 as compared to the second quarter of 2015. Increased customer rates of $5.7 million, primarily due to the July 2015 increase in Missouri electric rates, net of a $1.4 million decrease resulting from a lowering of Missouri base fuel recovery, contributed an estimated $4.3 million to revenues. The impact of weather and other volumetric related factors increased revenues an estimated $1.8 million. Improved customer counts increased revenues an estimated $0.8 million. A $2.3 million decrease in Missouri fuel recovery revenue and a $1.9 million decrease 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.

Although revenues decreased for the six months and twelve months ended June 30, 2016 periods, electric margins increased for these same periods. The decrease in revenues for both periods was driven primarily by decreases in fuel recovery revenues which have little impact on margin.

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Total revenues for our on-system customers decreased $3.7 million for the six months ended June 30, 2016 as compared to the same period in 2015, driven by a $5.4 million decrease in Missouri fuel recovery revenue and a $1.2 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. Revenue changes impacting margin included increased customer rates of $12.9 million, primarily due to the July 2015 increase in Missouri electric rates, net of a $2.9 million decrease resulting from a lowering of Missouri base fuel recovery, which contributed an estimated $10.0 million to revenues. Improved customer counts increased revenues an estimated $1.5 million. However, weather and other volumetric related factors decreased revenues an estimated $8.6 million.

Revenues for our on-system customers decreased $4.2 million for the twelve months ended June 30, 2016 as compared to the same period in 2015, driven by a $9.4 million decrease in Missouri fuel recovery revenue and a $2.0 million decrease in non-Missouri fuel recovery revenue, both of which were offset by a corresponding change in fuel expenses, resulting in no net effect on gross margin. Revenue changes impacting margin included increased customer rates of $22.7 million, primarily due to the July 2015 increase in Missouri electric rates, net of a $5.5 million decrease resulting from a lowering of Missouri base fuel recovery, which contributed an estimated $17.2 million to revenues. Improved customer counts increased revenues an estimated $2.7 million. However, weather and other volumetric related factors decreased revenues an estimated $12.7 million during the twelve months ended June 30, 2016, negatively impacting revenues.

Fuel expense decreases during all periods ended June 30, 2016, reflective of the content and timing of the non-Missouri fuel recovery and deferral 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) for the applicable periods ended June 30, 2016 as compared to the same periods in 2015 (in millions):

	Three Months			Six Months			Twelve Months
	Ended			Ended			Ended
Regulated operating expense:	2016 vs. 2015			2016vs. 2015			2016 vs. 2015
Transmission expense	$	(0.7	)	$	(0.9	)	$	(0.4	)
Distribution expense	(0.1		)	(0.1		)	(0.5		)
Power operation expense	(0.2		)	(1.5		)	(0.9		)
Employee health care expense	0.1			0.0			0.8
Employee pension expense	(0.1		)	(0.3		)	(0.5		)
General office supplies and expense(1)	1.0			2.4			3.6
Administrative and general expense	0.1			(0.3		)	(0.2		)
Allowance for uncollectible accounts	(0.2		)	(0.3		)	(0.7		)
Other miscellaneous accounts (netted)	0.0			0.0			(0.2		)
TOTAL	$	(0.1	)	$	(1.0	)	$	1.0

(1) Mainly due to increases in executive stock compensation of $0.5 million, $1.9 million and $2.8 million for the three month, six month and twelve month periods ended June 30, 2016, respectively.

The table below shows maintenance and repairs expense increases/(decreases) for the applicable periods ended June 30, 2016 as compared to the same periods in 2015 (in millions):

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	Three Months			Six Months			Twelve Months
	Ended			Ended			Ended
	2016 vs. 2015			2016 vs. 2015			2016 vs. 2015
Transmission and distribution maintenance expense	$	(0.7	)	$	(1.1	)	$	(2.3	)
Maintenance and repairs expense at:
Energy Center	0.8			0.5			(0.6		)
Asbury plant	0.9			0.8			0.4
SLCC	(3.1		)(1)	(3.4		)(1)	(3.5		)(1)
State Line plant	(0.1		)	(0.1		)	(0.4		)
Iatan plant	(0.6		)	(0.7		)	(0.9		)
Plum Point plant	(0.2		)	1.0			0.9
Riverton plant	0.1			0.0			0.7		(2)
Water plant	0.0			0.0			0.2
Other miscellaneous accounts (netted)	0.1			0.1			0.1
TOTAL	$	(2.8	)	$	(2.9	)	$	(5.4	)

(1) Mainly due to timing differences of a planned maintenance outage in 2015.

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

In connection with the Merger Agreement and the pending Merger, we incurred approximately $4.2 million of merger related expenses in the second quarter of 2016 and $8.4 million during the six months and twelve months ended June 30, 2016.

Depreciation and amortization expense increased approximately $0.6 million (3.4%), $1.0 million (2.6%) and $4.2 million (5.9%) during the three month, six month and twelve month periods ended June 30, 2016, respectively, primarily due to increased plant in service.

Other taxes were virtually the same during the three months ended June 30, 2016 as compared to the previous year. Other taxes decreased $0.3 million during the six month period ended June 30, 2016 and increased approximately $1.1 million during the twelve month period ended June 30, 2016.

Gas Segment

Gas Operating Revenues and Sales

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

Total Gas Delivered to Customers

	Three Months Ended				Six Months Ended				Twelve Months Ended
(bcf sales)	2016	2015	% change		2016	2015	% change		2016	2015	% change
Residential	0.21	0.21	(2.6	)%	1.31	1.48	(11.6	)%	2.05	2.44	(16.2	)%
Commercial	0.11	0.12	(7.1	)	0.58	0.66	(11.9	)	0.97	1.14	(14.7	)
Industrial	0.00	0.00	(46.1	)	0.02	0.02	(21.9	)	0.03	0.04	(20.9	)
Other(1)	0.00	0.00	35.4		0.02	0.02	5.1		0.03	0.03	(2.3	)
Total retail sales	0.32	0.33	(4.5	)	1.93	2.18	(11.6	)	3.08	3.65	(15.6	)
Transportation sales	0.85	0.98	(13.0	)	2.14	2.44	(12.3	)	4.15	4.74	(12.4	)
Total gas operating sales	1.17	1.31	(10.8	)	4.07	4.62	(12.0	)	7.23	8.39	(13.8	)

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

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

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Operating Revenues and Cost of Gas Sold

	Three Months Ended						Six Months Ended						Twelve Months Ended
($ in millions)	2016		2015		% change		2016		2015		% change		2016		2015		% change
Residential	$	3.4	$	3.8	(9.7	)%	$	13.2	$	16.8	(21.2	)%	$	22.7	$	29.4	(22.7	)%
Commercial	1.3		1.5		(15.0	)	5.1		6.7		(23.4	)	9.1		12.0		(23.9	)
Industrial	0.0		0.0		(47.0	)	0.1		0.2		(36.2	)	0.3		0.4		(32.3	)
Other(1)	0.1		0.0		5.7		0.2		0.2		(11.6	)	0.3		0.3		(14.9	)
Total retail revenues	$	4.8	$	5.3	(11.4	)	$	18.6	$	23.9	(21.9	)	$	32.4	$	42.1	(23.1	)
Other revenues	0.1		0.1		(15.9	)	0.2		0.2		(16.4	)	0.4		0.4		(12.4	)
Transportation revenues	0.8		0.8		(0.4	)	1.9		2.0		(3.9	)	3.6		3.9		(6.0	)
Total gas operating revenues	$	5.7	$	6.2	(10.2	)	$	20.7	$	26.1	(20.5	)	$	36.4	$	46.4	(21.5	)
Cost of gas sold	1.5		2.0		(27.6	)	9.0		13.5		(32.9	)	15.1		22.8		(33.8	)
Gas segment gross margins	$	4.2	$	4.2	(1.8	)	$	11.7	$	12.6	(7.3	)	$	21.3	$	23.6	(9.7	)

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

Gas retail sales and revenues decreased during all periods presented during 2016 as compared to the comparable periods in 2015 reflecting decreased demand due to milder temperatures. Although heating degree days were 5.5% more in the second quarter of 2016 as compared to the second quarter of 2015 they were 18.1% less than the 30-year average. Total heating degree days for the 2015-2016 gas heating season (which runs from November to March) were 20.6% less than the 2014-2015 gas heating season and 18.5% less than the 30-year average gas heating season. As a result, our gas gross margin (defined as gas operating revenues less cost of gas in rates) decreased slightly during the three months ended June 30, 2016 and decreased $0.9 million and $2.3 million, during the six month and twelve month periods ended June 30, 2016, respectively.

We have a PGA clause in place that allows us to recover from our customers, subject to routine regulatory review, the cost of purchased gas supplies, transportation and storage, including costs associated with the use of financial instruments to hedge the purchase price of natural gas. Pursuant to the provisions of the PGA clause, the difference between actual costs incurred and costs recovered through the application of the PGA are reflected as a regulatory asset or regulatory liability until the balance is recovered from or credited to customers. As of June 30, 2016, we had $0.6 million recorded as a non-current regulatory liability.

Operating Revenue Deductions

The table below shows regulated operating expense increases/(decreases) for the applicable periods ended June 30, 2016 as compared to the same periods in 2015 (in millions):

	Three Months Ended			Six Months Ended			Twelve Months Ended
	2016 vs. 2015			2016 vs. 2015			2016 vs. 2015
Transmission and distribution operation expense	$	(0.1	)	$	(0.1	)	$	0.1
Administrative and general expense	0.1			0.3			0.5
Customer accounts expense	0.0			(0.1		)	(0.3		)
Other miscellaneous accounts (netted)	(0.1		)	0.0			0.0
TOTAL	$	(0.1	)	$	0.1		$	0.3

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 June 30:

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	Three Months Ended						Six-Months Ended						Twelve Months Ended
	2016			2015			2016			2015			2016			2015
Consolidated provision for income taxes	$	5.7		$	4.0		$	14.3		$	12.8		$	35.3		$	33.3
Consolidated effective federal and state income tax rates	38.1		%	37.4		%	38.1		%	37.4		%	37.7		%	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 June 30. AFUDC decreased during the twelve months ended June 30, 2016 as compared to the same period in 2015, reflecting the completion of the environmental retrofit project at our Asbury plant in December 2014. AFUDC increased during the six months ended June 30, 2016 as compared to the same period in 2015 reflecting construction of the Riverton 12 combined cycle project. AFUDC decreased during the three months ended June 30, 2016 as compared to the same period in 2015 reflecting completion of the Riverton 12 combined cycle project.

	Three Months Ended				Six Months Ended				Twelve Months Ended
($ in millions)	2016		2015		2016		2015		2016		2015
Allowance for equity funds used during construction	$	1.1	$	1.2	$	2.7	$	2.2	$	5.4	$	5.9
Allowance for borrowed funds used during construction	0.6		0.7		1.7		1.3		3.2		3.2
Total AFUDC	$	1.7	$	1.9	$	4.4	$	3.5	$	8.6	$	9.1

Total interest charges on long-term and short-term debt for the periods ended June 30 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 on August 20, 2015 of $60.0 million of 3.59% First Mortgage Bonds due 2030. The proceeds from both bond issuances were used to refinance existing short-term indebtedness and for general corporate purposes.

	Interest Charges
	3 Months	3 Months			6 Months	6 Months			12 Months	12 Months
	Ended	Ended	%		Ended	Ended	%		Ended	Ended	%
($ in millions)	2016	2015	Change		2016	2015	Change		2016	2015	Change
Long-term debt interest	11.3	10.8	5.1	%	22.6	21.5	5.1	%	44.9	41.9	7.1	%
Short-term debt interest	0.0	0.1	(72.7	)	0.1	0.2	(47.6	)	0.2	0.3	(29.5	)
Other interest	0.3	0.3	0.3		0.6	0.5	9.2		1.1	1.0	7.1
Total interest charges	11.6	11.2	4.3		23.3	22.2	4.8		46.2	43.2	6.9

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

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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 June 21, 2016, we announced we had filed a Unanimous Stipulation and Agreement (Agreement) with the MPSC, which, if approved, allows an annual increase in base revenues of approximately $20.4 million, or 4.46 %. Base revenues established by the agreement are lower than the originally requested level of $33.4 million due primarily to lower fuel and purchased power costs than those built into current customer rates. The offsetting effect of reduced revenues and costs results in little impact to gross margin. If approved, new rates are expected to become effective in mid-September 2016. The most significant factor driving the rate request was the cost associated with the conversion of the Riverton Unit 12 natural gas combustion turbine to combined cycle operation. The Agreement calls for the Fuel Adjustment Charge to remain in effect. In addition, a tracking mechanism for non-labor operating and maintenance expenses for the Riverton 12 Combined Cycle Unit will continue and tracking of pension and other post-employment benefit expenses will continue.

On July 1, 2016, we filed a Notice of Intended Case Filing with the Kansas Corporation Commission of our intentions to file an electric rate case in Kansas on or after August 1, 2016.

On July 21, 2016, we filed a request with the Arkansas Public Service Commission to implement a cost recovery rider for the conversion of the existing Riverton Unit 12 to combined cycle operation.

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

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

SPP/Midcontinent Independent System Operator (MISO) Joint Operating Agreement and Plum Point Delivery: Due to Plum Point’s physical location and interconnection, transmission service from Entergy/MISO is required for delivery. On December 19, 2013, Entergy voluntarily integrated its generation, transmission, and load into the MISO regional transmission organization. Based on the current terms and conditions of MISO membership, Entergy’s participation in MISO has increased transmission delivery costs for our Plum Point power station as well as utilized 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 proceeded through settlement discussions and a resulting settlement agreement was filed with the FERC on February 25, 2016. The settlement closed on June 23, 2016 and we withdrew all claims on July 6, 2016.

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 June 30:

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Summary of Cash Flows

	Six Months Ended June 30,
(in millions)	2016			2015			Change
Cash provided by/(used in):
Operating activities	$	82.4		$	74.1		$	8.3
Investing activities	(68.5		)	(107.2		)	38.7
Financing activities	(14.0		)	33.0			(47.0		)
Net change in cash and cash equivalents	$	(0.1	)	$	(0.1	)	$	0.0

Cash flow from Operating Activities

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

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

Six Months Ended June 30, 2016 Compared to 2015. During the six months ended June 30, 2016, our net cash flows provided from operating activities increased $8.3 million or 11.1% from 2015. This change resulted primarily from the following:

· Increase in net income - $1.8 million.

· Lower pension contributions - $15.3 million.

· Changes to deferred taxes, primarily related to tax depreciation and recognition of tax net operating losses - $5.0 million.

· Net changes in fuel deferral mechanisms — $2.6 million.

· Adjustments related to stock compensation valuations - $1.9 million.

· Increase in plant related depreciation - $1.2 million.

· Changes in pension and OPEB regulatory amortizations - $0.9 million.

· Working capital changes for accounts receivable, accounts payable and other current assets and liabilities - $(14.8) million.

· Changes in regulatory amortizations - $(6.3) million.

Capital Requirements and Investing Activities

Our net cash flows used in investing activities decreased $38.7 million during the six months ended June 30, 2016 as compared to the same period in 2015, primarily due to a decrease in capital expenditures for the Riverton 12 combined cycle construction period over period reflecting the completion of the combined cycle unit in April 2016.

Our capital expenditures incurred totaled approximately $65.2 million during the six months ended June 30, 2016 compared to $101.1 million for the six months ended June 30, 2015.

A breakdown of the capital expenditures for the six months ended June 30, 2016 and 2015 is as follows (in millions):

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	Capital Expenditures
	2016		2015
Distribution and transmission system additions	$	35.0	$	33.5
New Generation — Riverton 12 combined cycle	14.5		49.8
Additions and replacements — electric plant	5.9		8.4
Gas segment additions and replacements	1.8		1.5
Transportation	3.7		1.7
Other (including retirements and salvage -net) (1)	3.7		4.9
Subtotal	64.6		99.8
Non-regulated capital expenditures (primarily fiber optics)	0.6		1.3
Subtotal capital expenditures incurred (2)	65.2		101.1
Adjusted for capital expenditures payable (3)	3.3		6.1
Total cash outlay	$	68.5	$	107.2

(1) Other includes equity AFUDC of $(2.7) million for 2016 and $(2.2) million 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.

Approximately 59.6% of our cash requirements for capital expenditures during the second quarter of 2016 were satisfied from internally generated funds (funds provided by operating activities less dividends paid). The remaining amounts of such requirements were satisfied from short-term borrowings and proceeds from our sales of common stock discussed below.

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

Six Months Ended June 30, 2016 compared to Six Months Ended June 30, 2015

Our net cash flows used in financing activities was $14.0 million in the six months ended June 30, 2016, as compared to $33.0 million provided by financing activities in the six months ended June 30, 2015, a decrease of $47.0 million, primarily due to the following:

· Net short-term borrowings of $5.5 million in the six months ended June 30, 2016 as compared to $53.0 million during six months ended June 30, 2015.

· Proceeds from issuance of common stock of $3.6 million during the six months ended June 30, 2016 as compared to $2.9 million during the six months ended June 30, 2015.

· Dividends paid of $22.9 million during the six months ended June 30, 2016 as compared to $22.7 million during the six months ended June 30, 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 June 30, 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.

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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.

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 June 30, 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 June 30, 2016, this test would allow us to issue approximately $12.4 million principal amount of new first mortgage bonds at an assumed interest rate of 5.5%. As of June 30, 2016, we are in compliance with all restrictive covenants of the EDG Mortgage.

Credit Ratings

Currently, our 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

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On March 4, 2016, Moody’s reaffirmed our credit ratings and outlook. On April 29, 2016, Standard & Poor’s reaffirmed our credit ratings and outlook. On December 15, 2015, Standard & Poor’s had 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. A security rating is not a recommendation to buy, sell or hold securities. Each rating is subject to revision or withdrawal at any time by the assigning rating organization. Each security rating agency has its own methodology for assigning ratings, and, accordingly, each rating should be considered independently of all other ratings.

CONTRACTUAL OBLIGATIONS

Our contractual obligations have not materially changed at June 30, 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 July 28, 2016, the Board of Directors declared a quarterly dividend of $0.26 per share on common stock payable on September 15, 2016 to holders of record as of September 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 AND ESTIMATES

See “Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report on Form 10-K for the year ended December 31, 2015 for a discussion of additional critical accounting policies. There were no changes in these policies in the quarter ended June 30, 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 often are extremely volatile. This volatility impacts our cost of power purchased and our participation in energy trades. If we were unable to generate an

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adequate supply of electricity for our customers, we would attempt to purchase power from others. Such supplies are not always available. In addition, congestion on the transmission system can limit our ability to make purchases from (or sell into) the wholesale markets.

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

Commodity Price Risk.

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

We satisfied 65.0% of our 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 June 30, 2016, 63%, or 5.6 million Dths’s, 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 June 30, 2016, our natural gas expenditures would increase by approximately $1.7 million based on our June 30, 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 June 30, 2016, we have 1.6 million Dths in storage on the three pipelines that serve our customers. This represents 79% 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

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contracts with other counterparties that resulted from us exceeding agreed-upon credit limits established by the counterparties. The following table depicts our margin deposit assets at June 30, 2016 and December 31, 2015 (in millions).

	June 30, 2016		December 31, 2015

Margin deposit assets	$	4.6	$	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 exposure at June 30, 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	$	3.4
Net unrealized mark-to-market losses for financial natural gas contracts	3.2
Net credit exposure	$	6.6

The $3.2 million net unrealized mark-to-market loss for financial natural gas contracts is comprised of $3.4 million that our counterparties are exposed to Empire for unrealized losses, and $0.2 million Empire is exposed to two counterparties. 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 June 30, 2016, we have $4.6 million on deposit for NYMEX contract exposure to Empire, of which $3.5 million represents our collateral requirement. If NYMEX gas prices decreased 25% from their June 30, 2016 levels, our collateral requirement would increase $8.8 million. If these prices increased 25%, our collateral requirement would decrease $3.4 million. Our other counterparties would not be required to post collateral with Empire.

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

Interest Rate Risk.

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

If market interest rates average 1% more in 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).

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Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of June 30, 2016.

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

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

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

Item 1A. Risk Factors.

There have been no material changes to the factors disclosed in Part I, Item 1-A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2015.

Item 5. Other Information.

For the twelve months ended June 30, 2016, our ratio of earnings to fixed charges was 2.67x. See Exhibit (12) hereto.

Item 6. Exhibits.

(a) Exhibits.

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

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

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

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

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

(101) The following financial information from The Empire District Electric Company’s Quarterly Report on Form 10-Q for the period ended June 30, 2016, filed with the SEC on August 5, 2016, formatted in Extensible Business Reporting Language (XBRL): (i) the Consolidated Statements of Income for the three, six and twelve month periods ended June 30, 2016 and 2015, (ii) the Consolidated Balance Sheets at June 30, 2016 and December 31, 2015, (iii) the Consolidated Statements of Cash Flows for the six-month periods ended June 30, 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.

**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

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incorporated by reference into, or part of a registration statement, prospectus or other document filed under the Securities Act of 1933, as amended or the Exchange Act of 1934, as amended except as shall be expressly set forth by specific reference in such filings.

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SIGNATURES

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

	THE EMPIRE DISTRICT ELECTRIC COMPANY
	Registrant


	By	/s/ Laurie A. Delano
		Laurie A. Delano
		Vice President — Finance and Chief Financial Officer


	By	/s/ Robert W. Sager
		Robert W. Sager
		Controller, Assistant Secretary and Assistant Treasurer

August 5, 2016

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