10-Q

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended September 30, 2016

or

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

For the transition period from                to             .

Commission file number: 1-3368

THE EMPIRE DISTRICT ELECTRIC COMPANY

(Exact name of registrant as specified in its charter)

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

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

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

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

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

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

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 October 31, 2016, 44,094,312 shares of common stock were outstanding.

THE EMPIRE DISTRICT ELECTRIC COMPANY

INDEX

			PAGE
	Forward Looking Statements		3
Part I -	Financial Information:
Item 1.	Financial Statements:
	a.	Consolidated Statements of Income	5
	b.	Consolidated Balance Sheets	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		35
	Rate Matters		41
	Markets and Transmission		42
	Liquidity and Capital Resources		43
	Contractual Obligations		46
	Dividends		46
	Off-Balance Sheet Arrangements		47
	Critical Accounting Policies and Estimates		47
	Recently Issued Accounting Standards		47
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		47
Item 4.	Controls and Procedures		49
Part II-	Other Information:
Item 1.	Legal Proceedings		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		50
Item 6.	Exhibits		50
	Signatures		51

2

FORWARD LOOKING STATEMENTS

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

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

·the impact of energy efficiency and alternative energy sources, including solar;

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

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

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

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

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

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

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

·electric utility restructuring, including deregulation;

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

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

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

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

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

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

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

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

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

·changes in accounting requirements;

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

·performance of acquired businesses;

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

·certain risks and uncertainties associated with the Merger 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;

3

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

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

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

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

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

·the timing to consummate the proposed transaction;

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

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

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

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

All such factors are difficult to predict, contain uncertainties that may materially affect actual results, and may be beyond our control. Additional risks and uncertainties have been 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.

4

PART I.  FINANCIAL INFORMATION

Item 1.  Financial Statements

THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

	Three Months Ended
	September 30
	2016			2015
	(000’s except per share amounts)
Operating revenues:
Electric	$	169,070		$	162,412
Gas	4,559			5,084
Other	1,725			2,218
	175,354			169,714
Operating revenue deductions:
Fuel and purchased power	45,795			45,795
Cost of natural gas sold and transported	861			1,301
Regulated operating expenses	27,224			28,437
Other operating expenses	740			879
Maintenance and repairs	10,456			11,454
Merger related expenses	252			—
Depreciation and amortization	23,852			20,090
Provision for income taxes	17,115			15,850
Other taxes	10,045			10,125
	136,340			133,931
Operating income	39,014			35,783
Other income and (deductions):
Allowance for equity funds used during construction	234			1,257
Interest income	26			2
Benefit for other income taxes	145			586
Other — non-operating expense, net	(449		)	(1,751		)
	(44		)	94
Interest charges:
Long-term debt	11,298			11,001
Short-term debt	25			80
Allowance for borrowed funds used during construction	(140		)	(743		)
Other	282			254
	11,465			10,592
Net income	$	27,505		$	25,285
Weighted average number of common shares outstanding - basic	44,049			43,728
Weighted average number of common shares outstanding - diluted	44,106			43,819
Total earnings per weighted average share of common stock — basic and diluted	$	0.62		$	0.58
Dividends declared per share of common stock	$	0.26		$	0.26

See accompanying Notes to Consolidated Financial Statements.

5

THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

	Nine Months Ended
	September 30,
	2016			2015
	(000’s except per share amounts)
Operating revenues:
Electric	$	435,256		$	431,335
Gas	25,313			31,181
Other	5,421			6,299
	465,990			468,815
Operating revenue deductions:
Fuel and purchased power	121,140			133,926
Cost of natural gas sold and transported	9,900			14,765
Regulated operating expenses	82,554			84,656
Other operating expenses	2,555			2,474
Maintenance and repairs	33,387			37,303
Merger related expenses	8,691			—
Depreciation and amortization	65,073			60,237
Provision for income taxes	31,582			28,789
Other taxes	29,474			30,121
	384,356			392,271
Operating income	81,634			76,544
Other income and (deductions):
Allowance for equity funds used during construction	3,000			3,469
Interest income	80			142
Benefit for other income taxes	298			713
Other — non-operating expense, net	(1,219		)	(2,675		)
	2,159			1,649
Interest charges:
Long-term debt	33,895			32,504
Short-term debt	113			247
Allowance for borrowed funds used during construction	(1,809		)	(2,030		)
Other	855			780
	33,054			31,501
Net income	$	50,739		$	46,692
Weighted average number of common shares outstanding - basic	43,962			43,629
Weighted average number of common shares outstanding - diluted	44,007			43,721
Total earnings per weighted average share of common stock — basic and diluted	$	1.15		$	1.07
Dividends declared per share of common stock	$	0.78		$	0.78

See accompanying Notes to Consolidated Financial Statements.

6

THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

	Twelve Months Ended
	September 30,
	2016			2015
	(000’s except per share amounts)
Operating revenues:
Electric	$	559,005		$	565,471
Gas	35,835			46,437
Other	7,907			8,271
	602,747			620,179
Operating revenue deductions:
Fuel and purchased power	157,074			182,494
Cost of natural gas sold and transported	14,636			22,860
Regulated operating expenses	111,449			112,094
Other operating expenses	3,392			3,217
Maintenance and repairs	44,605			50,424
Merger related expenses	8,691			—
Depreciation and amortization	85,386			78,774
Provision for income taxes	37,593			35,500
Other taxes	38,531			38,971
	501,357			524,334
Operating income	101,390			95,845
Other income and (deductions):
Allowance for equity funds used during construction	4,382			5,317
Interest income	83			145
Benefit for other income taxes	572			687
Other — non-operating expense, net	(1,972		)	(3,019		)
	3,065			3,130
Interest charges:
Long-term debt	45,193			42,824
Short-term debt	130			298
Allowance for borrowed funds used during construction	(2,623		)	(2,984		)
Other	1,111			1,033
	43,811			41,171
Net income	$	60,644		$	57,804
Weighted average number of common shares outstanding — basic	43,920			43,583
Weighted average number of common shares outstanding — diluted	43,956			43,677
Total earnings per weighted average share of common stock — basic	$	1.38		$	1.33
Total earnings per weighted average share of common stock — diluted	$	1.38		$	1.32
Dividends declared per share of common stock	$	1.04		$	1.04

See accompanying Notes to Consolidated Financial Statements.

7

THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS (UNAUDITED)

	September 30, 2016		December 31, 2015
	($-000’s)
Assets
Plant and property, at original cost:
Electric	$	2,695,201	$	2,473,927
Gas	86,438		83,402
Other	45,001		44,263
Construction work in progress	31,840		183,689
	2,858,480		2,785,281
Accumulated depreciation and amortization	809,510		764,895
	2,048,970		2,020,386
Current assets:
Cash and cash equivalents	7,931		1,753
Restricted cash	4,728		4,726
Accounts receivable — trade, net of allowance $726 and $623, respectively	51,873		40,162
Accrued unbilled revenues	17,952		20,653
Accounts receivable — other	14,835		28,320
Fuel, materials and supplies	57,515		60,950
Prepaid expenses and other	11,346		8,835
Unrealized gain in fair value of derivative contracts	4,527		1,295
Regulatory assets	7,127		7,052
	177,834		173,746
Noncurrent assets and deferred charges:
Regulatory assets	207,154		209,708
Goodwill	39,492		39,492
Unrealized gain in fair value of derivative contracts	7		16
Other	3,100		3,297
	249,753		252,513
Total Assets	$	2,476,557	$	2,446,645

(Continued)

See accompanying Notes to Consolidated Financial Statements.

8

THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS (UNAUDITED) (Continued)

	September 30, 2016		December 31, 2015
	($-000’s)
Capitalization and Liabilities
Common stock, $1 par value, 44,080,737 and 43,820,726 shares issued and outstanding, respectively	$	44,081	$	43,821
Capital in excess of par value	664,523		657,466
Retained earnings	117,869		101,443
Total common stockholders’ equity	826,473		802,730
Long-term debt (net of current portion):
Obligations under capital lease	3,335		3,580
First mortgage bonds and secured debt	725,313		724,838
Unsecured debt	100,978		100,935
Total long-term debt	829,626		829,353
Total long-term debt and common stockholders’ equity	1,656,099		1,632,083
Current liabilities:
Accounts payable and accrued liabilities	44,487		66,946
Current maturities of long-term debt	25,312		25,246
Short-term debt	—		25,000
Regulatory liabilities	17,724		8,615
Customer deposits	15,156		14,623
Interest accrued	15,213		7,348
Unrealized loss in fair value of derivative contracts	2,118		4,472
Taxes accrued	19,294		2,832
Other current liabilities	246		323
	139,550		155,405
Commitments and contingencies (Note 7)
Noncurrent liabilities and deferred credits:
Regulatory liabilities	131,778		132,457
Deferred income taxes	428,066		396,542
Unamortized investment tax credits	18,374		18,487
Pension and other postretirement benefit obligations	74,095		82,144
Unrealized loss in fair value of derivative contracts	1,520		3,696
Other	27,075		25,831
	680,908		659,157
Total Capitalization and Liabilities	$	2,476,557	$	2,446,645

See accompanying Notes to Consolidated Financial Statements.

9

THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

	Nine Months Ended
	September 30,
	2016			2015
	($-000’s)
Operating activities:
Net income	$	50,739		$	46,692
Adjustments to reconcile net income to cash flows from operating activities:
Depreciation and amortization including regulatory items	63,593			67,099
Pension and other postretirement benefit costs, net of contributions	(2,105		)	(12,038		)
Deferred income taxes and unamortized investment tax credit, net	31,284			28,237
Allowance for equity funds used during construction	(3,000		)	(3,469		)
Stock compensation expense	4,116			1,507
Non-cash (gain)/loss on derivatives	3,368			4,892
Other	99			(45		)
Cash flows impacted by changes in:
Accounts receivable and accrued unbilled revenues	862			14,496
Fuel, materials and supplies	3,435			(2,495		)
Prepaid expenses, other current assets and deferred charges	(13,533		)	(5,813		)
Accounts payable and accrued liabilities	(19,167		)	(24,621		)
Asset retirement obligations	(188		)	(27		)
Interest, taxes accrued and customer deposits	24,860			25,457
Other liabilities and other deferred credits	11,200			5,818
Net cash provided by operating activities	155,563			145,690
Investing activities:
Capital expenditures — regulated	(94,330		)	(145,886		)
Capital expenditures and other investments — non-regulated	(682		)	(1,828		)
Restricted cash	(1		)	—
Net cash used in investing activities	(95,013		)	(147,714		)
Financing activities:
Proceeds from first mortgage bonds, net	—			60,000
Long-term debt issuance costs	—			(519		)
Proceeds from issuance of common stock, net of issuance costs	5,173			4,307
Net short-term debt borrowings/(repayments)	(25,000		)	(27,750		)
Dividends	(34,313		)	(34,042		)
Other	(232		)	(217		)
Net cash provided by (used in) financing activities	(54,372		)	1,779
Net increase (decrease) in cash and cash equivalents	6,178			(245		)
Cash and cash equivalents at beginning of period	1,753			2,105
Cash and cash equivalents at end of period	$	7,931		$	1,860

See accompanying Notes to Consolidated Financial Statements.

10

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

Note 1 - Summary of Significant Accounting Policies

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

The accompanying interim financial statements do not include all disclosures included in the annual financial statements and therefore should be read in conjunction with the financial statements and notes thereto included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2015.

The information furnished reflects all adjustments, consisting only of normal recurring adjustments, which are in our opinion necessary to state fairly the results for the interim periods as well as present these periods on a consistent basis with the financial statements for the fiscal year ended December 31, 2015.

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

Note 2 - Recently Issued and Proposed Accounting Standards

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 $8.1 million in unamortized debt issuance costs being reclassified from deferred charges to long-term debt on the September 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

11

liabilities, and cash flow classification. This guidance will be effective for periods beginning after December 15, 2016. The application of this standard is not expected to have a material impact on our results of operations, financial position or liquidity.

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.

Classification of Certain Cash Receipts and Cash Payments:  In August 2016 the FASB issued revised guidance addressing the classification of eight specific cash receipts and cash payments in the statement of cash flows.  The revised guidance is intended to reduce diversity in practice in how these items were being classified.  The new 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 sheet (in thousands).

Regulatory Assets and Liabilities

	September 30, 2016			December 31, 2015
Regulatory Assets:
Current:
Under recovered fuel costs	$	7		$	196
Current portion of long-term regulatory assets	7,120			6,856
Regulatory assets, current	7,127			7,052
Long-term:
Pension and other postretirement benefits(1)	101,307			108,273
Income taxes	48,581			48,613
Deferred construction accounting costs(2)	14,712			14,977
Unamortized loss on reacquired debt	9,226			9,731
Unsettled derivative losses — electric segment	3,323			7,775
System reliability — vegetation management	2,164			3,604
Storm costs	3,118			3,531
Asset retirement obligation	10,493			7,722
Customer programs	6,677			5,942
Missouri solar initiative(3)	10,897			3,504
Current portion of long-term regulatory assets	(7,120		)	(6,856		)
Unrecovered fuel costs	1,089			—
Other	2,687			2,892
Regulatory assets, long-term	207,154			209,708
Total Regulatory Assets	$	214,281		$	216,760
	September 30, 2016			December 31, 2015
Regulatory Liabilities:
Current:
Over recovered fuel costs	$	14,416		$	5,280
Current portion of long-term regulatory liabilities	3,308			3,335
Regulatory liabilities, current	17,724			8,615
Long-term:
Costs of removal(4)	98,265			94,193
SWPA payment for Ozark Beach lost generation	12,300			14,213
Income taxes	11,083			11,244
Deferred construction accounting costs — fuel(5)	7,574			7,690
Unamortized gain on interest rate derivative	2,904			3,031
Pension and other postretirement benefits	895			1,745
Over recovered fuel costs	2,065			2,300
System reliability — vegetation management	—			1,320
Current portion of long-term regulatory liabilities	(3,308		)	(3,335		)
Other	—			56
Regulatory liabilities, long-term	131,778			132,457
Total Regulatory Liabilities	$	149,502		$	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 841 solar rebate applications processed and internal costs as of September 30, 2016, (compared to 262 as of December 31, 2015), resulting in solar rebate-related costs totaling approximately $10.9 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 cost 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 September 30, 2016 and December 31, 2015, we have recorded the following assets and liabilities representing the fair value of derivative financial instruments, (in thousands):

		September 30,		December 31,
ASSET DERIVATIVES		2016		2015
Hedging instruments	Balance Sheet Classification	Fair Value		Fair Value
Natural gas contracts, gas segment	Current assets	$	121	$	2
	Non-current assets and deferred charges - other	7		16
Natural gas contracts, electric segment	Current assets	1,039		—
	Non-current assets and deferred charges - other			—
Transmission congestion rights, electric segment	Current assets	3,367		1,293
Total derivatives assets		$	4,534	$	1,311
		September 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	2,118		4,190
	Non-current liabilities and deferred credits	1,520		3,630
Total derivatives liabilities		$	3,638	$	8,168

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Electric Segment

At September 30, 2016, approximately $1.1 million of unrealized net losses are applicable to natural gas financial instruments which will settle within the next twelve months.

The following tables set forth “mark-to-market” pre-tax gains/(losses) from non-designated derivative instruments for the electric segment for each of the periods ended September 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						Nine Months Ended						Twelve Months Ended
Electric Segment	Derivative	2016			2015			2016			2015			2016			2015
Commodity contracts	Regulatory (assets)/liabilities	$	(1,678	)	$	(1,690	)	$	1,705		$	(3,909	)	$	(1,240	)	$	(10,152	)
Transmission congestion rights	Regulatory (assets)/liabilities	398			125			5,939			4,750			6,158			6,322
Total Electric Segment		$	(1,280	)	$	(1,565	)	$	7,644		$	841		$	4,918		$	(3,830	)
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						Nine Months Ended						Twelve Months Ended
Electric Segment	Derivative	2016			2015			2016			2015			2016			2015
Commodity contracts	Fuel and purchased power expense	$	(2,231	)	$	(4,104	)	$	(3,774	)	$	(6,381	)	$	(5,508	)	$	(7,105	)
Transmission congestion rights	Fuel and purchased power expense	1,468			1,133			3,811			6,446			4,833			8,653
Total Electric Segment		$	(763	)	$	(2,971	)	$	37		$	65		$	(675	)	$	1,548

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 September 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	33	%	—	1,160,000	$	3.122	Up to 100%
2017	41	%	782,900	5,210,000	$	3.347	60%
2018	20	%	565,000	2,460,000	$	3.334	40%
2019	10	%	—	1,460,000	$	2.955	20%
2020	0	%	—	—	$	—	10%

At September 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	Estimated Fair Value
2016-17	8,464	$	3,367

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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 September 30, 2016, we had 1.8 million Dths in storage on the three pipelines that serve our customers. This represents 86% 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 September 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	—	1,751	65	%
Nov. 2017 – Mar. 2018	Up to 50%	280	—	—	9	%
Nov. 2018 – Mar. 2019	Up to 20%	0	—	—	0	%

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 September 30, (in thousands).

Non-Designated Hedging	Balance Sheet Classification of	Amount of Gain/(Loss) Recognized on Balance Sheet
Instruments Due to Regulatory	Gain / (Loss) on	Three Months Ended						Nine Months Ended					Twelve Months Ended
Accounting - Gas Segment	Derivative	2016			2015			2016		2015			2016			2015
Commodity contracts	Regulatory (assets)/liabilities	$	(65	)	$	(236	)	$	107	$	(50	)	$	(289	)	$	(647	)
Total - Gas Segment		$	(65	)	$	(236	)	$	107	$	(50	)	$	(289	)	$	(647	)

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 September 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)	September 30, 2016		December 31, 2015
Margin deposit assets	$	4.2	$	11.2

Offsetting of derivative assets and liabilities

We believe that entering into master trading and netting agreements mitigates the level of financial loss that could result from a default under derivatives agreements by allowing net settlement of derivative assets and liabilities. We generally enter into the following master trading and netting agreements: (1) the International Swaps and Derivatives Association Agreement, a standardized

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

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

	Fair Value Measurements at Reporting Date Using
($ in 000’s) Description	Assets/(Liabilities) at Fair Value			Quoted Prices in Active Markets for Identical Assets/(Liabilities) (Level 1)			Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
September 30, 2016
Derivative assets	$	4,534		$	1,167		$	3,367	$	—
Derivative liabilities	$	(3,638	)	$	(3,638	)	$	—	$	—
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 September 30, 2016 and December 31, 2015 was $851 million. The fair market value at September 30, 2016 was approximately $910 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 September 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 September 30, 2016, we were in compliance with this covenant as our ratio of total indebtedness was 51% 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 September 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. As of September 30, 2016, there were no outstanding borrowings under either the credit agreement or our commercial paper program which the credit agreement backs.

On October 20, 2016, the revolving credit facility was amended such that the pending Merger would not trigger the credit agreement’s change of control provision. The revolving credit facility will remain in place after the Merger closing.

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.

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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 of settlement will be subject to customary conditions and 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 and the parties anticipate this will take place after the closing of the Merger. 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 September 30, 2016 (in millions).

	Firm physical gas and transportation contracts		Coal and coal transportation contracts
October 1, 2016 through December 31, 2016	$	4.2	$	1.6
January 1, 2017 through December 31, 2018	37.4		14.5
January 1, 2019 through December 31, 2020	28.8		2.2
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 September 30, 2016, are detailed in the table above. Our existing railroad agreement was modified and became effective on October 1, 2016. Our contractual obligations, as reflected in the table above, were reduced as a result of the amendment. The amended terms continue to allow us to operate the Asbury plant up to full load capacity.

Purchased Power

We have three purchased power agreements.

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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 $270.1 million through August 31, 2039, the end date of the agreement.

We have a long-term purchased power agreement, which expires in 2028, with Cloud County Windfarm, LLC, 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 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 September 30, 2016 were $167.8 million for the project to date, excluding AFUDC. Final costs are estimated to range from $167.8 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 September 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.

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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:

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 from defenders and challengers of the climate rule were heard before a ten-judge panel on September 27, 2016. The D.C. court is expected to decide the case by late February 2017. If, however, the case is appealed to the Supreme Court, the matter is likely to continue into 2018.

Other than the cancellation of the initial submittal deadline in September 2016, 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

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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 at our Asbury plant is expected to require the closure of the existing ash impoundment, construction of a new utility waste landfill and conversion of the existing bottom ash handling from a wet to a dry system. 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 MDNR has issued a draft construction permit, and approval of the final permit for the utility waste landfill is expected by February 2017.

At this time, we anticipate CCR/ELG compliance costs to be approximately $15-$30 million. This estimate is based on our current capital budget, information gathered to date in relation to the multiple CCR Rule reports, and the current execution plan. As we move forward through the ELG and CCR rules’ timelines of compliance, these plans may change. Currently, the landfill construction and bottom ash conversion are anticipated to be complete by early 2019. The CCR impoundment will be closed within five years after inactivity. 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

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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 September 30, 2016, we had processed 841 solar rebate applications resulting in solar rebate-related costs totaling approximately $10.9 million under the new tariff. We have recorded the $10.9 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.

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 September 30,
	Pension Benefits						SERP						OPEB
	2016			2015			2016			2015			2016			2015
Service cost	$	1,752		$	1,816		$	41		$	33		$	826		$	945
Interest cost	2,669			2,702			110			102			1,188			1,175
Expected return on plan assets	(3,387		)	(3,396		)	—			—			(1,375		)	(1,272		)
Amortization of prior service cost (1)	(157		)	(157		)	(4		)	(10		)	(253		)	(253		)
Amortization of net actuarial loss (1)	2,313			2,835			149			168			326			699
Net periodic benefit cost	$	3,190		$	3,800		$	296		$	293		$	712		$	1,294

	Nine months ended September 30,
	Pension Benefits						SERP						OPEB
	2016			2015			2016			2015			2016			2015
Service cost	$	5,650		$	5,581		$	132		$	119		$	2,453		$	2,785
Interest cost	7,936			7,708			325			286			3,501			3,502
Expected return on plan assets	(10,318		)	(10,175		)	—			—			(4,124		)	(3,897		)
Amortization of prior service cost (1)	(472		)	(472		)	(11		)	(32		)	(758		)	(758		)
Amortization of net actuarial loss (1)	6,526			7,525			427			448			841			2,061
Net periodic benefit cost	$	9,322		$	10,167		$	873		$	821		$	1,913		$	3,693

	Twelve months ended September 30,
	Pension Benefits						SERP						OPEB
	2016			2015			2016			2015			2016			2015
Service cost	$	7,511		$	7,198		$	171		$	157		$	3,382		$	3,435
Interest cost	10,505			10,413			421			383			4,668			4,592
Expected return on plan assets	(13,709		)	(13,452		)	—			—			(5,423		)	(5,097		)
Amortization of prior service cost (1)	(630		)	(368		)	(21		)	(34		)	(1,011		)	(1,011		)
Amortization of net actuarial loss (1)	9,034			9,178			576			574			1,528			2,303
Net periodic benefit cost	$	12,711		$	12,969		$	1,147		$	1,080		$	3,144		$	4,222

(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 received 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 have made contributions totaling $12.5 million through the nine months ended September 30, 2016. No additional contributions are expected for the remainder of the year. Our OPEB funding policy is to contribute annually an amount at least equal to the

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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 $1.8 million as of September 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 September 30, 2016, there were 707,735 shares available for issuance in this plan.

	2016		2015
Subscriptions outstanding at September 30	25,118		59,463
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 $1.8 million as of September 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 September 30 (in thousands):

	Three Months Ended				Nine Months Ended				Twelve Months Ended
	2016		2015		2016		2015		2016		2015
Compensation Expense	$	1,302	$	598	$	4,211	$	1,659	$	6,832	$	2,976
Tax Benefit Recognized	485		213		1,565		592		2,549		1,081

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Time-Vested Restricted Stock Awards

Our time-vested restricted stock awards vest after a three-year period. No dividend rights accumulate during the vesting period. Time-vested restricted stock is valued at an amount equal to the fair market value of our common stock on the date of grant. If employment terminates during the vesting period because of death, retirement, or disability, the participant is entitled to a pro-rata portion of the time-vested restricted stock awards such participant would otherwise have earned, which is distributed following the date of termination, with the remainder of the award forfeited. If employment is terminated during the vesting period for reasons other than those listed above, the time-vested restricted stock awards will be forfeited on the date of the termination, unless the Board of Directors Compensation Committee determines, in its sole discretion, that the participant is entitled to a pro-rata portion of the award. In addition, if a change in control occurs during the vesting period, a pro-rata portion of the time-vested restricted stock awards will vest upon such change in control, and any portion of such awards that remains unvested immediately after the change in control will be forfeited. Consummation of the Merger will constitute a change of control.

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 September 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 September 30, 2016 and 2015 and changes during the nine months ended September 30, 2016 and 2015 were as follows:

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	2016				2015
			Weighted				Weighted
	Number of		Average Grant		Number 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 September 30,	66,788		$	27.22	69,021		$	24.38

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 September 30 (in thousands):

	Three Months Ended		Three Months Ended		Nine Months Ended		Nine Months Ended		Twelve Months Ended		Twelve Months Ended
	2016		2015		2016		2015		2016		2015
Electric transmission and distribution expense	$	5,340	$	7,325	$	18,802	$	21,839	$	25,856	$	28,619
Natural gas transmission and distribution expense	610		592		1,933		1,997		2,635		2,558
Power operation expense (other than fuel)	4,466		4,258		12,505		13,813		16,955		17,708
Customer accounts and assistance expense	2,712		2,649		8,252		8,142		11,047		10,889
Employee pension expense (1)	3,574		2,769		8,843		8,170		11,459		10,797
Employee healthcare expense (1)	2,691		3,022		7,373		7,640		9,895		9,970
General office supplies and expense	4,157		3,352		12,434		9,032		17,840		13,591
Administrative and general expense	2,935		3,650		10,594		11,647		13,810		15,061
Allowance for uncollectible accounts	651		705		1,530		2,050		1,560		2,453
Miscellaneous expense	88		115		288		326		392		448
Total	$	27,224	$	28,437	$	82,554	$	84,656	$	111,449	$	112,094

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

Note 11— Segment Information

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

	For the three months ended September 30, 2016
($-000’s)	Electric		Gas			Other		Eliminations			Total
Statement of Income Information
Revenues	$	169,070	$	4,559		$	2,070	$	(345	)	$	175,354
Depreciation and amortization	22,365		1,009			478		—			23,852
Federal and state income taxes	17,065		(420		)	325		—			16,970
Operating income	38,250		249			515		—			39,014
Interest income	25		5			26		(30		)	26
Interest expense	10,668		967			—		(30		)	11,605
Income from AFUDC (debt and equity)	369		5			—		—			374
Net income	27,691		(714		)	528		—			27,505
Capital Expenditures	$	23,715	$	1,261		$	104	—			$	25,080

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	For the three months ended September 30, 2015
($-000’s)	Electric		Gas			Other		Eliminations			Total
Statement of Income Information
Revenues	$	162,412	$	5,084		$	2,563	$	(345	)	$	169,714
Depreciation and amortization	18,651		984			455		—			20,090
Federal and state income taxes	15,137		(340		)	467		—			15,264
Operating income	34,622		413			748		—			35,783
Interest income	1		6			12		(17		)	2
Interest expense	10,384		968			—		(17		)	11,335
Income from AFUDC (debt and equity)	1,997		3			—		—			2,000
Net income	25,086		(560		)	759		—			25,285
Capital Expenditures	$	39,867	$	2,009		$	470				$	42,346

	For the nine months ended September 30, 2016
($-000’s)	Electric		Gas		Other		Eliminations			Total
Statement of Income Information
Revenues	$	435,256	$	25,313	$	6,455	$	(1,034	)	$	465,990
Depreciation and amortization	60,599		3,010		1,464		—			65,073
Federal and state income taxes	30,293		57		934		—			31,284
Operating income	77,195		2,977		1,462		—			81,634
Interest income	69		30		75		(94		)	80
Interest expense	32,054		2,903		—		(94		)	34,863
Income from AFUDC (debt and equity)	4,798		11		—		—			4,809
Net income	49,139		81		1,519		—			50,739
Capital Expenditures	$	86,366	$	3,264	$	682				$	90,312

	For the nine months ended September 30, 2015
($-000’s)	Electric		Gas		Other		Eliminations			Total
Statement of Income Information
Revenues	$	431,335	$	31,181	$	7,334	$	(1,035	)	$	468,815
Depreciation and amortization	55,930		2,932		1,375		—			60,237
Federal and state income taxes	26,296		454		1,326		—			28,076
Operating income	70,791		3,629		2,124		—			76,544
Interest income	128		34		33		(53		)	142
Interest expense	30,686		2,898		—		(53		)	33,531
Income from AFUDC (debt and equity)	5,493		6		—		—			5,499
Net income	43,809		728		2,155		—			46,692
Capital Expenditures	$	137,977	$	3,679	$	1,824				$	143,480

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	For the twelve months ended September 30, 2016
($-000’s)	Electric		Gas		Other		Eliminations			Total
Statement of Income Information
Revenues	$	559,005	$	35,835	$	9,286	$	(1,379	)	$	602,747
Depreciation and amortization	79,402		4,001		1,983		—			85,386
Federal and state income taxes	35,121		403		1,497		—			37,021
Operating income	94,527		4,501		2,362		—			101,390
Interest income	74		32		90		(113		)	83
Interest expense	42,675		3,872		—		(113		)	46,434
Income from AFUDC (debt and equity)	6,987		18		—		—			7,005
Net income	57,569		641		2,434		—			60,644
Capital Expenditures	$	117,500	$	4,775	$	1,082				$	123,357

	For the twelve months ended September 30, 2015
($-000’s)	Electric		Gas		Other		Eliminations			Total
Statement of Income Information
Revenues	$	565,471	$	46,437	$	9,650	$	(1,379	)	$	620,179
Depreciation and amortization	72,971		3,902		1,901		—			78,774
Federal and state income taxes	31,894		1,230		1,689		—			34,813
Operating income	87,188		5,859		2,798		—			95,845
Interest income	131		36		40		(62		)	145
Interest expense	40,352		3,865		—		(62		)	44,155
Income from AFUDC (debt and equity)	8,290		11		—		—			8,301
Net Income	53,005		1,981		2,818		—			57,804
Capital Expenditures	$	199,189	$	5,431	$	2,656				$	207,276

	As of September 30, 2016
($-000’s)	Electric		Gas(1)		Other		Eliminations			Total
Balance Sheet Information
Total assets	$	2,362,639	$	124,544	$	39,470	$	(50,096	)	$	2,476,557

(1) Includes goodwill of $39,492.

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

(1) Includes goodwill of $39,492.

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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 September 30:

	Three Months Ended						Nine Months Ended						Twelve Months Ended
	2016			2015			2016			2015			2016			2015
Consolidated provision for income taxes	$	17.0		$	15.3		$	31.3		$	28.1		$	37.0		$	34.8
Consolidated effective federal and state income tax rates	38.2		%	37.6		%	38.1		%	37.6		%	37.9		%	37.6		%

The effective income tax rate for the three, nine and twelve month periods ended September 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 September 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 utilized $43.8 million of the 2014 tax NOLs on our 2015 return. We also anticipate incurring a $17.0 million NOL in 2016 mostly due to bonus depreciation we expect to utilize on our recently completed Riverton Combined Cycle Plant project. As of September 30, 2016, we estimate there are $12.4 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 2016 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.

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

The closing of the Merger is subject to certain conditions, including, among others, approval of Empire shareholders, expiration or termination of the applicable Hart-Scott-Rodino Act (HSR Act) 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

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subsidiaries (including Empire and its subsidiaries), taken as a whole. As discussed below, all approvals have been received except for approval from the KCC.

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 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.

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. We received an order on September 29, 2016 from the APSC approving the Merger.

On August 4, 2016, we filed a non-unanimous stipulation and agreement with the staff of the MPSC. On September 7, 2016, we received an order from the MPSC approving the Merger, effective October 7, 2016.

On October 6, 2016, we announced a filing with the KCC of a Unanimous Settlement Agreement with respect to the joint application for approval of the Merger filed March 16, 2016. The Unanimous Settlement Agreement is subject to approval by the KCC. As a condition of the Unanimous Settlement Agreement that was reached with the KCC staff, our pending Kansas rate case is to be withdrawn and current base rates are to remain in effect through January 1, 2019. A decision from Kansas regulators is due no later than January 10, 2017, with an expected transaction close early in 2017.

In connection with each of the regulatory agreements noted above, Liberty Utilities Co. has agreed to certain commitments regarding ongoing service to Empire customers, employment of Empire personnel, cost sharing mechanisms, and compliance with existing regulatory stipulations in the normal course of business.

In connection with entering into the Merger Agreement, Empire has incurred approximately $8.7 million of transaction costs as of September 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 September 30, 2016, our gross operating revenues were derived as follows:

Electric segment sales*	92.7	%
Gas segment sales	6.0
Other segment sales	1.3

*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 of settlement will be subject to customary conditions and will provide for, among other things,

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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, and the parties anticipate this will take place after the closing of the Merger. 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. As discussed below, all approvals have been received except for Kansas.

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 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.

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. We received an order on September 29, 2016 from the APSC approving the Merger.

On August 4, 2016, we filed a non-unanimous stipulation and agreement with the staff of the MPSC. On September 7, 2016, we received an order from the MPSC approving the Merger, effective October 7, 2016.

On October 6, 2016, we announced a filing with the KCC of a Unanimous Settlement Agreement with respect to the joint application for approval of the Merger filed March 16, 2016. The Unanimous Settlement Agreement is subject to approval by the KCC. As a condition of the Unanimous Settlement Agreement that was reached with the KCC staff, our pending Kansas rate case is to be withdrawn and current base rates are to remain in effect through January 1, 2019. A decision from Kansas regulators is due no later than January 10, 2017, with an expected transaction close early in 2017.

Earnings

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

	Three Months Ended				Nine Months Ended				Twelve Months Ended
	2016		2015		2016		2015		2016		2015
Basic earnings per weighted average share of common stock	$	0.62	$	0.58	$	1.15	$	1.07	$	1.38	$	1.33
Diluted earnings per weighted average share of common stock	$	0.62	$	0.58	$	1.15	$	1.07	$	1.38	$	1.32

Electric segment gross margin increased during all periods ended September 30, 2016 compared to 2015, reflecting increased electric rates for our Missouri customers effective July 26, 2015 and September 14, 2016.

Electric earnings for the three months ended September 30, 2016 were positively impacted by the Missouri rate increases mentioned above as well as warmer weather and decreases in regulated operating and maintenance expenses as compared to the same period in 2015.

Electric earnings for the nine months ended September 30, 2016 were positively impacted by the Missouri rate increases 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.

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Electric earnings for the twelve months ended September 30, 2016 were positively impacted by the Missouri rate increases and decreases in regulated operating and 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 in all periods presented by increased depreciation and interest expense, reduced AFUDC and merger related expenses of approximately $0.3 million during the three months ended September 30, 2016 and $8.7 million in both the nine months ended and twelve months ended September 30, 2016 periods.

The table below sets forth a reconciliation of basic and diluted earnings per share (EPS) between the three months, nine months and twelve months ended September 30, 2015 and September 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 September 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			Nine Months Ended			Twelve Months Ended
Earnings Per Share — 2015	$	0.58		$	1.07		$	1.33
Gross margins
Electric segment	$	0.09		$	0.23		$	0.27
Gas segment	0.00			(0.01		)	(0.03		)
Other segment	(0.01		)	(0.01		)	(0.01		)
Total Gross Margin	0.08			0.21			0.23
Operating — electric segment	0.02			0.03			0.01
Operating —gas segment	0.00			0.00			0.00
Maintenance and repairs	0.01			0.05			0.08
Merger related expenses	0.00			(0.12		)	(0.12		)
Depreciation and amortization	(0.05		)	(0.07		)	(0.09		)
Other taxes	0.00			0.01			0.00
AFUDC	(0.02		)	(0.01		)	(0.02		)
Change in effective income tax rates	(0.01		)	(0.01		)	(0.01		)
Interest charges	0.00			(0.02		)	(0.03		)
Other income and deductions	0.02			0.02			0.01
Dilutive effect of additional shares issued	(0.01		)	(0.01		)	(0.01		)
Earnings Per Share — 2016	$	0.62		$	1.15		$	1.38

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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. This ruling permits us to request such rate reciprocity, but it does not require the OCC to grant such requests.

On June 21, 2016, we announced we had filed a Unanimous Stipulation and Agreement (Agreement) with the MPSC. The MPSC issued an order approving the Agreement on August 10, 2016 with rates effective September 14, 2016. The Agreement 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 reduced fuel costs results in little impact to gross margin. 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 September 23, 2016, we filed with the OCC for a change in rates for Oklahoma customers pursuant to the rate reciprocity rule mentioned above, seeking an annual increase in base revenues of approximately $4.7 million, or approximately 37.8% for Oklahoma electric customers. The OCC issued an order on October 13, 2016 rejecting the Missouri rates filed under the reciprocity rule. On November 2, 2016, we filed an application requesting that the current case be dismissed and filed a notice of intent to file an application seeking to implement a plan which would modify the rates and charges for our Oklahoma jurisdiction customers.

On September 16, 2016, we filed a request with the Kansas Corporation Commission (KCC) for changes in rates for our Kansas electric customers, seeking an annual increase in total revenue of approximately $6.4 million, or approximately 25.7%. On October 6, 2016, we announced a filing with the KCC of a Unanimous Settlement Agreement with respect to the joint application for approval of the Merger filed March 16, 2016. The Unanimous Settlement Agreement is subject to approval by the KCC. As a condition of the Unanimous Settlement Agreement that was reached with the KCC staff, our pending Kansas rate case is to be withdrawn and current base rates are to remain in effect through January 1, 2019. The agreement also provides that we may file a request to update the current Environmental Recovery Rider in Kansas to include costs associated with the Riverton 12 Combined Cycle project, which would produce approximately $1.2 million of additional revenue annually.

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. The rider request was approved on October 25, 2016 and we will begin collecting approximately $0.6 million of additional annual revenue on November 1, 2016.

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)”.

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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, nine, and twelve-month periods ended September 30, 2016, compared to the same periods ended September 30, 2015.

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

	Three Months Ended						Nine Months Ended				Twelve Months Ended
	2016			2015			2016		2015		2016		2015
Electric	$	27.7		$	25.1		$	49.1	$	43.8	$	57.6	$	53.0
Gas	(0.7		)	(0.6		)	0.1		0.7		0.6		2.0
Other	0.5			0.8			1.5		2.2		2.4		2.8
Net income	$	27.5		$	25.3		$	50.7	$	46.7	$	60.6	$	57.8

Electric Segment

Electric operating revenues comprised approximately 96.4% of our total operating revenues during the third 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 September 30, were as follows (in millions):

	kWh Sales
	3 Months	3 Months			9 Months	9 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	540.9	514.5	5.1	%	1,413.3	1,451.1	(2.6	)%	1,798.4	1,895.0	(5.1	)%
Commercial	443.8	436.9	1.6		1,197.6	1,208.1	(0.9	)	1,566.9	1,594.7	(1.7	)
Industrial	288.9	286.9	0.7		814.4	804.3	1.3		1,074.7	1,061.1	1.3
Wholesale on-system	95.6	93.2	2.6		255.0	255.3	(0.1	)	330.5	334.9	(1.3	)
Other(2)	34.8	34.6	0.5		99.7	99.2	0.5		131.6	129.9	1.4
Total on-system sales	1,404.0	1,366.1	2.8		3,780.0	3,818.0	(1.0	)	4,902.1	5,015.6	(2.3	)

(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 2.8% primarily due to increased demand resulting from warmer weather in the third quarter of 2016 as compared to the third quarter of 2015. Total cooling degree days (the cumulative number of degrees that the daily average temperature for each day during that period was above 65° F) for the third quarter of 2016 were 14.4% more than the same period last year and 20.5% more than the 30-year average. KWh sales for our residential and commercial customers increased mainly due to the warmer weather. Industrial sales increased 0.7% mainly due to increased usage.

KWh sales for our on-system customers decreased 1.0% during the nine months ended September 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.

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Residential kWh sales decreased 2.6% mainly due to the milder weather and decreased customer usage. Commercial kWh sales decreased 0.9%.  Industrial sales increased 1.3% mainly due to increased usage.

KWh sales for our on-system customers decreased 2.3% during the twelve months ended September 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, and other volumetric factors, as compared to the prior year periods. Residential and commercial kWh sales decreased primarily due to the milder weather during the twelve months ended September 30, 2016 and decreased customer usage. Industrial sales increased 1.3% 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 $6.7 million, $16.7 million and $19.0 million during the three month, nine month and twelve month periods ended September 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 expenditures to the fuel and purchased power expense shown on our statements of income) for the applicable periods ended September 30, were as follows (dollars in millions):

	Electric Segment Operating Revenues and Gross Margin
	3 Months			3 Months					9 Months			9 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	$	72.2		$	68.1		6.0	%	$	182.9		$	181.3		0.9	%	$	232.2		$	234.2		(0.9	)%
Commercial	50.0			49.8			0.5		130.6			132.3			(1.3	)	170.1			173.2			(1.8	)
Industrial	25.2			26.3			(4.0	)	66.4			67.7			(2.0	)	86.8			87.9			(1.2	)
Wholesale on-system	5.8			5.7			1.7		15.0			13.9			7.6		19.1			19.1			(0.1	)
Other(2)	4.4			4.4			(1.5	)	11.9			12.0			(0.7	)	15.6			15.6			0.3
Total on-system revenues	$	157.6		$	154.3		2.1		$	406.8		$	407.2		(0.1	)	$	523.8		$	530.0		(1.2	)
Off-system wholesale(3)	—			—					—			—					—			0.0			(100.0	)
SPP IM net revenues(3)	7.7			4.0			92.4		17.1			12.1			41.2		20.0			19.7			1.9
Total revenues from kWh sales	165.3			158.3			4.4		423.9			419.3			1.1		543.8			549.7			(1.1	)
Miscellaneous revenues(4)	3.2			3.5			(10.7	)	9.8			10.5			(6.2	)	13.1			13.7			(4.5	)
Total electric operating revenues	$	168.5		$	161.8		4.1		$	433.7		$	429.8		0.9		$	556.9		$	563.4		(1.2	)
Water revenues	0.6			0.6			1.2		1.5			1.5			0.7		2.1			2.1			0.9
Total electric segment operating revenues	$	169.1		$	162.4		4.1		$	435.2		$	431.3		0.9		$	559.0		$	565.5		(1.1	)
Actual fuel and purchased power expenditures(3)	44.2			41.3			7.0		112.7			111.0			1.5		142.7			145.5			(1.9	)
SPP IM net purchases(3)	1.5			5.9			(74.2	)	5.2			17.5			(70.3	)	10.3			30.6			(66.3	)
Net fuel recovery and deferral	0.6			(0.6		)	202.2		5.6			7.5			(25.4	)	6.9			8.6			(19.3	)
SWPA amortization(5)	(0.7		)	(0.7		)	(1.3	)	(1.9		)	(1.9		)	1.9		(2.5		)	(2.6		)	2.9
Unrealized (gain)/loss on derivatives	0.2			(0.1		)	189.5		(0.5		)	(0.2		)	(187.5	)	(0.3		)	0.4			(193.7	)
Total fuel and purchased power expense per income statement	$	45.8		$	45.8		0.0		$	121.1		$	133.9		(9.5	)	$	157.1		$	182.5		(13.9	)
Total Gross Margin	$	123.3		$	116.6		5.7		$	314.1		$	297.4		5.6		$	401.9		$	383.0		4.9

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

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

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

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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 $8.9 million of the Missouri portion remains to be amortized as of September 30, 2016.

Revenues for our on-system customers increased $3.3 million during the third quarter of 2016 as compared to the third quarter of 2015. The impact of weather and other volumetric related factors increased revenues an estimated $3.0 million. Increased customer rates of $5.0 million, primarily due to the July 2015 and September 2016 increases in Missouri electric rates, net of a $1.1 million decrease resulting from a lowering of Missouri base fuel recovery, contributed an estimated $3.9 million to revenues.  Improved customer counts increased revenues an estimated $1.1 million. A $2.2 million decrease in Missouri fuel recovery revenue and a $2.5 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 on-system revenues decreased for the nine months and twelve months ended September 30, 2016 periods, electric margins increased for these same periods. As discussed below, the decrease in revenues for both periods was driven primarily by decreases in fuel recovery revenues which have little impact on margin.

Total revenues for our on-system customers decreased $0.4 million for the nine months ended September 30, 2016 as compared to the same period in 2015, driven by a $7.6 million decrease in Missouri fuel recovery revenue and a $3.7 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. Weather and other volumetric related factors (mainly decreased customer usage) decreased revenues an estimated $5.7 million. Positive revenue changes included increased customer rates of $18.0 million, primarily due to the July 2015 increase in Missouri electric rates, net of a $4.1 million decrease resulting from a lowering of Missouri base fuel recovery, which contributed an estimated $13.9 million to revenues. Improved customer counts also increased revenues an estimated $2.7 million.

Revenues for our on-system customers decreased $6.2 million for the twelve months ended September 30, 2016 as compared to the same period in 2015 driven by a $9.5 million decrease in Missouri fuel recovery revenue and a $4.5 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. Weather and other volumetric related factors (mainly decreased customer usage) decreased revenues an estimated $13.7 million during the twelve months ended September 30, 2016, negatively impacting revenues. Positive revenue changes included increased customer rates of $23.7 million, primarily due to the July 2015 increase in Missouri electric rates, net of a $5.4 million decrease resulting from a lowering of Missouri base fuel recovery, which contributed an estimated $18.3 million to revenues. Improved customer counts increased revenues an estimated $3.2 million. Decreases in total fuel and purchased power expense during the twelve month period ended September 30, 2016, reflective of the content and timing of our various fuel mechanisms, 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.

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Operating Expenses — Other Than Fuel and Purchased Power

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

	Three Months			Nine Months			Twelve Months
	Ended			Ended			Ended
	2016 vs. 2015			2016 vs. 2015			2016 vs. 2015
Regulated operating expense:
Transmission expense(1)	$	(1.8	)	$	(2.7	)	$	(2.3	)
Distribution expense	(0.2		)	(0.4		)	(0.4		)
Power operation expense	0.2			(1.3		)	(0.8		)
Customer accounts and assistance expense	0.1			0.1			0.1
Employee pension expense	0.8			0.6			0.4
Employee health care expense	(0.4		)	(0.3		)	(0.1		)
General office supplies and expense(2)	0.7			3.1			3.9
Administrative and general expense	(0.7		)	(1.0		)	(1.2		)
Allowance for uncollectible accounts	0.0			(0.4		)	(0.5		)
Other miscellaneous accounts (netted)	—			—			—
TOTAL	$	(1.3	)	$	(2.3	)	$	(0.9	)

(1)Mainly due to a $1.8 million MISO Regional Through-and-Out refund received in the third quarter of 2016 and $2.1 million in refunds for the nine month ended and twelve month ended periods, of which approximately 50% was offset by a change in fuel expense through our Missouri fuel adjustment clause.

(2)Mainly due to increases in executive stock compensation of $0.7 million, $2.5 million and $3.6 million for the three month, nine month and twelve month periods ended September 30, 2016, respectively.

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

	Three Months			Nine Months			Twelve Months
	Ended			Ended			Ended
	2016 vs. 2015			2016 vs. 2015			2016 vs. 2015
Transmission and distribution maintenance expense(1)	$	(1.1	)	$	(2.2	)	$	(3.2	)
Maintenance and repairs expense at:
Energy Center	(0.6		)	—			(0.5		)
Asbury plant	—			0.8			0.4
SLCC	0.5			(2.9		)(2)	(2.7		)(2)
State Line plant	—			(0.1		)	(0.4		)
Iatan plant	(0.1		)	(0.9		)	(1.0		)
Plum Point plant	0.2			1.2			1.3
Riverton plant	—			(0.1		)	(0.1		)
Water plant	—			0.1			0.2
Other miscellaneous accounts (netted)	0.1			0.2			0.2
TOTAL	$	(1.0	)	$	(3.9	)	$	(5.8	)

(1) Mainly due to decreases in tree trimming maintenance expense.

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

In connection with the Merger Agreement and the pending Merger, we incurred approximately $0.3 million of merger related expenses in the third quarter of 2016 and $8.7 million during the nine months and twelve months ended September 30, 2016.

Depreciation and amortization expense increased approximately $3.7 million (19.9%), $4.7 million (8.3%) and $6.4 million (8.8%) during the three month, nine month and twelve month periods ended September 30, 2016, respectively, primarily due to increased plant in service and a $2.6 million one-time adjustment from our recent Missouri rate case.

Other taxes decreased $0.1 million and $0.4 million during the three month and nine month periods ended September 30, 2016, respectively. Other taxes increased approximately $0.1 million during the twelve month period ended September 30, 2016.

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Gas Segment

Gas Operating Revenues and Sales

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

Total Gas Delivered to Customers

	Three Months Ended				Nine Months Ended				Twelve Months Ended
			%				%				%
(bcf sales)	2016	2015	Change(1)		2016	2015	Change(1)		2016	2015	Change(1)
Residential	0.08	0.11	(24.3	)%	1.39	1.59	(12.4	)%	2.02	2.46	(17.8	)%
Commercial	0.10	0.10	(0.3	)	0.68	0.76	(10.4	)	0.97	1.14	(15.6	)
Industrial	0.01	0.00	28.6		0.03	0.03	(12.7	)	0.03	0.05	(23.4	)
Other(1)	0.00	0.00	(7.2	)	0.02	0.02	4.7		0.03	0.03	(3.2	)
Total retail sales	0.19	0.21	(11.8	)	2.12	2.40	(11.6	)	3.05	3.68	(17.1	)
Transportation sales	0.84	0.87	(3.0	)	2.98	3.31	(9.8	)	4.13	4.65	(11.2	)
Total gas operating sales	1.03	1.08	(4.8	)	5.10	5.71	(10.6	)	7.18	8.33	(13.8	)

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

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

Operating Revenues and Cost of Gas Sold

	Three Months Ended						Nine Months Ended						Twelve Months Ended
($ in millions)	2016		2015		% Change		2016		2015		% Change		2016		2015		% Change
Residential	$	2.5	$	2.8	(12.0	)%	$	15.7	$	19.6	(19.9	)%	$	22.4	$	29.5	(24.1	)%
Commercial	1.2		1.3		(13.0	)	6.3		8.0		(21.7	)	8.9		12.0		(25.4	)
Industrial	0.0		0.1		(8.1	)	0.2		0.3		(30.4	)	0.2		0.4		(37.4	)
Other(1)	0.0		0.0		(7.9	)	0.2		0.3		(11.2	)	0.3		0.3		(15.9	)
Total retail revenues	$	3.7	$	4.2	(12.3	)	$	22.4	$	28.2	(20.4	)	$	31.8	$	42.2	(24.6	)
Other revenues	0.1		0.1		(15.1	)	0.3		0.3		(16.0	)	0.4		0.4		(14.5	)
Transportation revenues	0.8		0.8		1.4		2.6		2.7		(2.4	)	3.6		3.8		(4.5	)
Total gas operating revenues	$	4.6	$	5.1	(10.3	)	$	25.3	$	31.2	(18.8	)	$	35.8	$	46.4	(22.8	)
Cost of gas sold	0.9		1.3		(33.8	)	9.9		14.8		(33.0	)	14.6		22.9		(36.0	)
Gas segment gross margins	$	3.7	$	3.8	(2.2	)	$	15.4	$	16.4	(6.1	)	$	21.2	$	23.5	(10.1	)

(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. 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 $0.1 million, $1.0 million and $2.4 million, during the three month, nine month and twelve month periods ended September 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 September 30, 2016, we had $1.0 million recorded as a non-current regulatory asset.

Operating Revenue Deductions

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

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	Three Months Ended		Nine Months Ended			Twelve Months Ended
(in millions)	2016 vs. 2015		2016 vs. 2015			2016 vs. 2015
Administrative and general expense	$	0.1	$	0.4		$	0.5
Customer accounts expense	—		(0.1		)	(0.3		)
Other miscellaneous accounts (netted)	—		(0.1		)	0.1
TOTAL	$	0.1	$	0.2		$	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 September 30:

	Three Months Ended						Nine Months Ended						Twelve Months Ended
	2016			2015			2016			2015			2016			2015
Consolidated provision for income taxes	$	17.0		$	15.3		$	31.3		$	28.1		$	37.0		$	34.8
Consolidated effective federal and state income tax rates	38.2		%	37.6		%	38.1		%	37.6		%	37.9		%	37.6		%

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 September 30. AFUDC decreased during the twelve months ended September 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 nine months ended September 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 September 30, 2016 as compared to the same period in 2015 reflecting completion of the Riverton 12 combined cycle project.

	Three Months Ended				Nine Months Ended				Twelve Months Ended
(in millions)	2016		2015		2016		2015		2016		2015
Allowance for equity funds used during construction	$	0.2	$	1.3	$	3.0	$	3.5	$	4.4	$	5.3
Allowance for borrowed funds used during construction	0.2		0.7		1.8		2.0		2.6		3.0
Total AFUDC	$	0.4	$	2.0	$	4.8	$	5.5	$	7.0	$	8.3

Total interest charges on long-term and short-term debt for the periods ended September 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
	Third		Third				9 Months		9 Months				12 Months		12 Months
	Quarter		Quarter		%		Ended		Ended		%		Ended		Ended		%
(in millions)	2016		2015		Change		2016		2015		Change		2016		2015		Change
Long-term debt interest	$	11.3	$	11.0	2.7	%	$	33.9	$	32.5	4.3	%	$	45.2	$	42.8	5.5	%
Short-term debt interest	0.0		0.1		(69.2	)	0.1		0.2		(54.5	)	0.1		0.3		(56.1	)
Other interest	0.3		0.2		10.8		0.9		0.8		9.7		1.1		1.0		7.5
Total interest charges	$	11.6	$	11.3	2.4		$	34.9	$	33.5	4.0		$	46.4	$	44.1	5.2

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RATE MATTERS

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

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

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

Jurisdiction	Date Requested	Annual Increase Granted		Percent Increase Granted		Date Effective
Missouri – Electric	October 16, 2015	$	20,390,000	4.46	%	September 14, 2016
Missouri – Electric	August 29, 2014	$	17,125,000	3.90	%	July 26, 2015
Kansas - Electric	December 5, 2014	$	782,479	4.71	%	June 1, 2015
Arkansas - Electric	February 23, 2015	$	457,000	3.35	%	February 23, 2015
Kansas - Electric	January 22, 2015	$	273,455	1.08	%	February 23, 2015
Arkansas - Electric	December 3, 2013	$	1,366,809	11.34	%	September 26, 2014
Missouri – Electric	July 6, 2012	$	27,500,000	6.78	%	April 1, 2013

On October 16, 2015, we filed a request with the Missouri Public Service Commission (MPSC) for changes in rates for our Missouri electric customers, 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. This ruling permits us to request such rate reciprocity, but it does not require the OCC to grant such requests.

On June 21, 2016, we announced we had filed a Unanimous Stipulation and Agreement (Agreement) with the MPSC. The MPSC issued an order approving the Agreement on August 10, 2016 with rates effective September 14, 2016. The Agreement 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 reduced fuel costs results in little impact to gross margin. 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 September 23, 2016, we filed with the OCC for a change in rates for Oklahoma customers pursuant to the rate reciprocity rule mentioned above, seeking an annual increase in base revenues of approximately $4.7 million, or approximately 37.8% for Oklahoma electric customers. The OCC issued an order on October 13, 2016 rejecting the Missouri rates filed under the reciprocity rule. On November 2, 2016, we filed an application requesting that the current case be dismissed and filed a

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notice of intent to file an application seeking to implement a plan which would modify the rates and charges for our Oklahoma jurisdiction customers.

On September 16, 2016, we filed a request with the Kansas Corporation Commission (KCC) for changes in rates for our Kansas electric customers, seeking an annual increase in total revenue of approximately $6.4 million, or approximately 25.7%. On October 6, 2016, we announced a filing with the KCC of a Unanimous Settlement Agreement with respect to the joint application for approval of the Merger filed March 16, 2016. The Unanimous Settlement Agreement is subject to approval by the KCC. As a condition of the Unanimous Settlement Agreement that was reached with the KCC staff, our pending Kansas rate case is to be withdrawn and current base rates are to remain in effect through January 1, 2019. The agreement also provides that we may file a request to update the current Environmental Recovery Rider in Kansas to include costs associated with the Riverton 12 Combined Cycle project, which would produce approximately $1.2 million of additional revenue annually.

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. The rider request was approved on October 25, 2016 and we will begin collecting approximately $0.6 million of additional annual revenue on November 1, 2016.

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

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

MARKETS AND TRANSMISSION

Electric Segment

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

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

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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. We have received a total of $2.1 million in MISO Regional Through-and-Out refunds in 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 nine months ended September 30 (in millions):

Summary of Cash Flows

	Nine Months Ended September 30,
	2016			2015			Change
Cash provided by/(used in):
Operating activities	$	155.6		$	145.7		$	9.9
Investing activities	(95.0		)	(147.7		)	52.7
Financing activities	(54.4		)	1.8			(56.2		)
Net change in cash and cash equivalents	$	6.2		$	(0.2	)	$	6.4

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.

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Nine Months Ended September 30, 2016 Compared to 2015.  During the nine months ended September 30, 2016 our net cash flows provided from operating activities increased $9.9 million, or 6.8%, from 2015. The increase is largely driven by changes in pension adjustments, deferred taxes, and regulated fuel treatment, while only partially offset by changes in customer receivables. Additional detailed changes are as follows:

·Increase in net income - $4.0 million.

·Lower pension contributions - $8.9 million.

·Net changes in fuel deferral mechanisms – $5.5 million.

·Increase in plant related depreciation - $5.0 million.

·Changes to deferred taxes, primarily related to accelerated tax depreciation and utilization of previous tax net operating losses - $3.0 million.

·Adjustments related to stock compensation valuations - $2.6 million.

·Working capital changes for accounts receivable, accounts payable and other current assets and liabilities - $(10.0) million.

·Amortizations related to regulatory fuel adjustment mechanisms - $(7.8) million.

·Changes in derivative loss positions - $(1.5) million.

Capital Requirements and Investing Activities

Our net cash flows used in investing activities decreased $52.7 million during the nine months ended September 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 $90.3 million during the nine months ended September 30, 2016, compared to $143.5 million for the nine months ended September 30, 2015.

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

	Capital Expenditures
(in millions)	2016		2015
Distribution and transmission system additions	$	51.6	$	49.5
New Generation – Riverton 12 combined cycle	14.5		68.6
Additions and replacements – electric plant	8.3		12.6
Gas segment additions and replacements	3.0		3.3
Transportation	3.8		2.7
Other (including retirements, insurance proceeds and salvage -net) (1)	8.4		5.0
Subtotal	89.6		141.7
Non-regulated capital expenditures (primarily fiber optics)	0.7		1.8
Subtotal capital expenditures incurred (2)	90.3		143.5
Adjusted for capital expenditures payable (3)	4.7		4.2
Total cash outlay	$	95.0	$	147.7

(1) Other includes equity AFUDC of $(3.0) million and $(3.5) million for 2016 and 2015, respectively.

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

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

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

We estimate that internally generated funds will provide 100.0% of the funds required for the remainder of our budgeted 2016 capital expenditures. If operating activities do not provide all of the funds required and additional financing is needed, we intend to utilize short-term debt.

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Financing Activities

Nine Months Ended September 30, 2016 compared to Nine Months Ended September 30, 2015

Our net cash flows used in financing activities was $54.4 million in the nine months ended September 30, 2016 as compared to $1.8 million provided by financing activities in the nine months ended September 30, 2015, a decrease of $56.2 million, primarily due to the following:

·No first mortgage bonds issued during the nine months ended September 30, 2016 compared to the issuance of $60.0 million of first mortgage bonds during the nine months ended September 30, 2015.

·Proceeds from issuance of common stock of $5.2 million during the nine months ended September 30, 2016 as compared to $4.3 million during the nine months ended September 30, 2015.

·Net short-term repayments of $25.0 million in the nine months ended September 30, 2016 as compared to net short-term repayments of $27.8 million during the nine months ended September, 2015.

·Dividends paid of $34.3 million during the nine months ended September 30, 2016 as compared to $34.0 million during the nine months ended September 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 September 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.

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. On October 20, 2016, the revolving credit facility was amended such that the pending Merger would not trigger the credit agreement’s change of control provision. The revolving credit facility will remain in place after the Merger closing. 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

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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 September 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 September 30, 2016, this test would allow us to issue approximately $10.7 million principal amount of new first mortgage bonds at an assumed interest rate of 5.5%. As of September 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

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 September 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

46

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 October 27, 2016, the Board of Directors declared a quarterly dividend of $0.26 per share on common stock payable on December 15, 2016 to holders of record as of December 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 September 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 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, 59% 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.

47

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 September 30, 2016, 33%, or 1.2 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 increased 10% more than the price at September 30, 2016, our natural gas expenditures would increase by approximately $1.9 million based on our September 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 September 30, 2016, we have 1.8 million Dths in storage on the three pipelines that serve our customers. This represents 86% of our storage capacity. We have an additional 0.5 million Dths hedged through financial derivatives and physical contracts.

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

Credit Risk.

In order to minimize overall credit risk, we maintain credit policies, including the evaluation of counterparty financial condition and the use of standardized agreements that facilitate the netting of cash flows associated with a single counterparty. See Note 4 of “Notes to Consolidated Financial Statements (Unaudited)” regarding agreements containing credit risk contingent features. In addition, certain counterparties make available collateral in the form of cash held as margin deposits as a result of exceeding agreed-upon credit exposure thresholds or may be required to prepay the transaction. Conversely, we are required to post collateral with counterparties at certain thresholds, which is typically the result of changes in commodity prices. Amounts reported as margin deposit liabilities represent counterparty funds we hold that result from various trading counterparties exceeding agreed-upon credit exposure thresholds. Amounts reported as margin deposit assets represent our funds held on deposit for our NYMEX contracts with our broker and other financial contracts with other counterparties that resulted from us exceeding agreed-upon credit limits established by the counterparties. The following table depicts our margin deposit assets at September 30, 2016 and December 31, 2015 (in millions).

	September 30, 2016		December 31, 2015
Margin deposit assets	$	4.2	$	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 September 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	$	1.2
Net unrealized mark-to-market losses for financial natural gas contracts	2.4
Net credit exposure	$	3.6

48

The $2.4 million net unrealized mark-to-market loss for financial natural gas contracts is comprised of $2.5 million that our counterparties are exposed to Empire for unrealized losses, and $0.1 million Empire is exposed to two counterparties. We are holding no collateral from any counterparty since they are below the $10.0 million mark-to-market collateral threshold in our agreements. As noted above, as of September 30, 2016, we have $4.2 million on deposit for NYMEX contract exposure to Empire, of which $4.0 million represents our collateral requirement. If NYMEX gas prices decreased 25% from their September 30, 2016 levels, our collateral requirement would increase $7.6 million. If these prices increased 25%, our collateral requirement would decrease $2.5 million. Our other counterparties would not be required to post collateral with Empire.

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

Interest Rate Risk.

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

If market interest rates average 1% more in 2016 than in 2015, our interest expense would increase, and income before taxes would decrease by less than $1.0 million. This amount has been determined by considering the impact of the hypothetical interest rates on our highest month-end commercial paper balance for 2015. These analyses do not consider the effects of the reduced level of overall economic activity that could exist in such an environment. In the event of a significant change in interest rates, management would likely take actions to further mitigate its exposure to the change. However, due to the uncertainty of the specific actions that would be taken and their possible effects, the sensitivity analysis assumes no changes in our financial structure.

Item 4.   Controls and Procedures

As of the end of the period covered by this report, an evaluation was carried out, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as such term is defined in Rule 13a-15(e) of the Securities Exchange Act of 1934). Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of September 30, 2016.

There have been no changes in our internal control over financial reporting that occurred during the third 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.

49

Item 5.  Other Information.

For the twelve months ended September 30, 2016, our ratio of earnings to fixed charges was 2.74x.  See Exhibit (12) hereto.

Item 6.  Exhibits.

(a)           Exhibits.

(10) First Amendment, dated as of October 20, 2016, to the Credit Agreement, dated as of October 20, 2014, among The Empire District Electric Company, Wells Fargo Bank, National Association, as Administrative Agent, Swingline Lender and Issuing Bank, and the lenders named therein (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K dated October 20, 2016 and filed October 24, 2016, File No. 1-03368).

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

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

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

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

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

(101) The following financial information from The Empire District Electric Company’s Quarterly Report on Form 10-Q for the period ended September 30, 2016, filed with the SEC on November 7, 2016, formatted in Extensible Business Reporting Language (XBRL): (i) the Consolidated Statements of Income for the three, nine and twelve month periods ended September 30, 2016 and 2015, (ii) the Consolidated Balance Sheets at September 30, 2016 and December 31, 2015, (iii) the Consolidated Statements of Cash Flows for the nine-month periods ended September 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 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.

50

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

November 7, 2016

51

EX-12

EXHIBIT (12)

COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES

	Twelve
	Months Ended
	September 30, 2016
Income before provision for income taxes and fixed charges (Note A)	$	153,906,420
Fixed charges:
Interest on long-term debt	$	45,193,071
Interest on short-term debt	130,636
Other interest	1,110,856
Rental expense representative of an interest factor (Note B)	9,807,802
Total fixed charges	$	56,242,365
Ratio of earnings to fixed charges	2.74x

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

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

EX-31.(A)

Exhibit (31)(a)

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

PURSUANT TO SECTION 302 OF THE

SARBANES-OXLEY ACT OF 2002

I, Bradley P. Beecher, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date: November 7, 2016

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

EX-31.(B)

Exhibit (31)(b)

CERTIFICATION OF CHIEF FINANCIAL OFFICER

PURSUANT TO SECTION 302 OF THE

SARBANES-OXLEY ACT OF 2002

I, Laurie A. Delano, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date: November 7, 2016

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

EX-32.(A)

Exhibit (32)(a)

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

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

In connection with the Quarterly Report of The Empire District Electric Company (the “Company”) on Form 10-Q for the period ending September 30, 2016 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), Bradley P. Beecher, as Chief Executive Officer of the Company, certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

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

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

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

Date:      November 7, 2016

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

EX-32.(B)

Exhibit (32)(b)

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

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

In connection with the Quarterly Report of The Empire District Electric Company (the “Company”) on Form 10-Q for the period ending September 30, 2016 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), Laurie A. Delano, as Chief Financial Officer of the Company, certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

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

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

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

Date:      November 7, 2016

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

XML

Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2016	Oct. 31, 2016
Document and Entity Information
Entity Registrant Name	EMPIRE DISTRICT ELECTRIC CO
Entity Central Index Key	0000032689
Document Type	10-Q
Document Period End Date	Sep. 30, 2016
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		44,094,312
Document Fiscal Year Focus	2016
Document Fiscal Period Focus	Q3

XML

Consolidated Statements of Income - USD ($) shares in Thousands, $ in Thousands	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Operating revenues:
Electric	$ 169,070	$ 162,412	$ 435,256	$ 431,335	$ 559,005	$ 565,471
Gas	4,559	5,084	25,313	31,181	35,835	46,437
Other	1,725	2,218	5,421	6,299	7,907	8,271
Total operating revenues	175,354	169,714	465,990	468,815	602,747	620,179
Operating revenue deductions:
Fuel and purchased power	45,795	45,795	121,140	133,926	157,074	182,494
Cost of natural gas sold and transported	861	1,301	9,900	14,765	14,636	22,860
Regulated operating expenses	27,224	28,437	82,554	84,656	111,449	112,094
Other operating expenses	740	879	2,555	2,474	3,392	3,217
Maintenance and repairs	10,456	11,454	33,387	37,303	44,605	50,424
Merger related expenses	252		8,691		8,691
Depreciation and amortization	23,852	20,090	65,073	60,237	85,386	78,774
Provision for income taxes	17,115	15,850	31,582	28,789	37,593	35,500
Other taxes	10,045	10,125	29,474	30,121	38,531	38,971
Total operating revenue deductions	136,340	133,931	384,356	392,271	501,357	524,334
Operating income	39,014	35,783	81,634	76,544	101,390	95,845
Other income and (deductions):
Allowance for equity funds used during construction	234	1,257	3,000	3,469	4,382	5,317
Interest income	26	2	80	142	83	145
Benefit for other income taxes	145	586	298	713	572	687
Other - non-operating expense, net	(449)	(1,751)	(1,219)	(2,675)	(1,972)	(3,019)
Total other income	(44)	94	2,159	1,649	3,065	3,130
Interest charges:
Long-term debt	11,298	11,001	33,895	32,504	45,193	42,824
Short-term debt	25	80	113	247	130	298
Allowance for borrowed funds used during construction	(140)	(743)	(1,809)	(2,030)	(2,623)	(2,984)
Other	282	254	855	780	1,111	1,033
Total interest charges	11,465	10,592	33,054	31,501	43,811	41,171
Net income	$ 27,505	$ 25,285	$ 50,739	$ 46,692	$ 60,644	$ 57,804
Weighted average number of common shares outstanding - basic (in shares)	44,049	43,728	43,962	43,629	43,920	43,583
Weighted average number of common shares outstanding - diluted (in shares)	44,106	43,819	44,007	43,721	43,956	43,677
Total earnings per weighted average share of common stock - basic and diluted (in dollars per share)	$ 0.62	$ 0.58	$ 1.15	$ 1.07
Total earnings per weighted average share of common stock - basic (in dollars per share)					$ 1.38	$ 1.33
Total earnings per weighted average share of common stock - diluted (in dollars per share					1.38	1.32
Dividends declared per share of common stock (in dollars per share)	$ 0.26	$ 0.26	$ 0.78	$ 0.78	$ 1.04	$ 1.04

XML

Consolidated Balance Sheets - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
Plant and property, at original cost:
Electric	$ 2,695,201	$ 2,473,927
Gas	86,438	83,402
Other	45,001	44,263
Construction work in progress	31,840	183,689
Total plant and property, Gross	2,858,480	2,785,281
Accumulated depreciation and amortization	809,510	764,895
Total plant and property, Net	2,048,970	2,020,386
Current assets:
Cash and cash equivalents	7,931	1,753
Restricted cash	4,728	4,726
Accounts receivable - trade, net of allowance $726 and $623, respectively	51,873	40,162
Accrued unbilled revenues	17,952	20,653
Accounts receivable - other	14,835	28,320
Fuel, materials and supplies	57,515	60,950
Prepaid expenses and other	11,346	8,835
Unrealized gain in fair value of derivative contracts	4,527	1,295
Regulatory assets	7,127	7,052
Total current assets	177,834	173,746
Noncurrent assets and deferred charges:
Regulatory assets	207,154	209,708
Goodwill	39,492	39,492
Unrealized gain in fair value of derivative contracts	7	16
Other	3,100	3,297
Total noncurrent assets and deferred charges	249,753	252,513
Total Assets	2,476,557	2,446,645
Capitalization and liabilities
Common stock, $1 par value, 44,080,737 and 43,820,726 shares issued and outstanding, respectively	44,081	43,821
Capital in excess of par value	664,523	657,466
Retained earnings	117,869	101,443
Total common stockholders' equity	826,473	802,730
Long-term debt (net of current portion):
Obligations under capital lease	3,335	3,580
First mortgage bonds and secured debt	725,313	724,838
Unsecured debt	100,978	100,935
Total long-term debt	829,626	829,353
Total long-term debt and common stockholders' equity	1,656,099	1,632,083
Current liabilities:
Accounts payable and accrued liabilities	44,487	66,946
Current maturities of long-term debt	25,312	25,246
Short-term debt		25,000
Regulatory liabilities	17,724	8,615
Customer deposits	15,156	14,623
Interest accrued	15,213	7,348
Unrealized loss in fair value of derivative contracts	2,118	4,472
Taxes accrued	19,294	2,832
Other current liabilities	246	323
Total current liabilities	139,550	155,405
Commitments and contingencies (Note 7)
Noncurrent liabilities and deferred credits:
Regulatory liabilities	131,778	132,457
Deferred income taxes	428,066	396,542
Unamortized investment tax credits	18,374	18,487
Pension and other postretirement benefit obligations	74,095	82,144
Unrealized loss in fair value of derivative contracts	1,520	3,696
Other	27,075	25,831
Total noncurrent liabilities	680,908	659,157
Total Capitalization and Liabilities	$ 2,476,557	$ 2,446,645

XML

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
Consolidated Balance Sheets
Accounts receivable - trade, allowance (in dollars)	$ 726	$ 623
Common stock, par value (in dollars per share)	$ 1	$ 1
Common stock, shares issued	44,080,737	43,820,726
Common stock, shares outstanding	44,080,737	43,820,726

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Consolidated Statements of Cash Flows - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015
Operating activities:
Net income	$ 50,739	$ 46,692
Adjustments to reconcile net income to cash flows from operating activities:
Depreciation and amortization including regulatory items	63,593	67,099
Pension and other postretirement benefit costs, net of contributions	(2,105)	(12,038)
Deferred income taxes and unamortized investment tax credit, net	31,284	28,237
Allowance for equity funds used during construction	(3,000)	(3,469)
Stock compensation expense	4,116	1,507
Non-cash (gain)/loss on derivatives	3,368	4,892
Other	99	(45)
Cash flows impacted by changes in:
Accounts receivable and accrued unbilled revenues	862	14,496
Fuel, materials and supplies	3,435	(2,495)
Prepaid expenses, other current assets and deferred charges	(13,533)	(5,813)
Accounts payable and accrued liabilities	(19,167)	(24,621)
Asset retirement obligations	(188)	(27)
Interest, taxes accrued and customer deposits	24,860	25,457
Other liabilities and other deferred credits	11,200	5,818
Net cash provided by operating activities	155,563	145,690
Investing activities:
Capital expenditures - regulated	(94,330)	(145,886)
Capital expenditures and other investments - non-regulated	(682)	(1,828)
Restricted cash	(1)
Net cash used in investing activities	(95,013)	(147,714)
Financing activities:
Proceeds from first mortgage bonds, net		60,000
Long-term debt issuance costs		(519)
Proceeds from issuance of common stock, net of issuance costs	5,173	4,307
Net short-term debt borrowings/(repayments)	(25,000)	(27,750)
Dividends	(34,313)	(34,042)
Other	(232)	(217)
Net cash provided by (used in) financing activities	(54,372)	1,779
Net increase (decrease) in cash and cash equivalents	6,178	(245)
Cash and cash equivalents at beginning of period	1,753	2,105
Cash and cash equivalents at end of period	$ 7,931	$ 1,860

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Summary of Significant Accounting Policies

9 Months Ended

Sep. 30, 2016

Summary of Significant Accounting Policies

Summary of Significant Accounting Policies

Note 1 - Summary of Significant Accounting Policies

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

The accompanying interim financial statements do not include all disclosures included in the annual financial statements and therefore should be read in conjunction with the financial statements and notes thereto included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2015.

The information furnished reflects all adjustments, consisting only of normal recurring adjustments, which are in our opinion necessary to state fairly the results for the interim periods as well as present these periods on a consistent basis with the financial statements for the fiscal year ended December 31, 2015.

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

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Recently Issued and Proposed Accounting Standards

9 Months Ended

Sep. 30, 2016

Recently Issued and Proposed Accounting Standards

Recently Issued and Proposed Accounting Standards

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 $8.1 million in unamortized debt issuance costs being reclassified from deferred charges to long-term debt on the September 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 liabilities, and cash flow classification. This guidance will be effective for periods beginning after December 15, 2016. The application of this standard is not expected to have a material impact on our results of operations, financial position or liquidity.

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.

Classification of Certain Cash Receipts and Cash Payments:  In August 2016 the FASB issued revised guidance addressing the classification of eight specific cash receipts and cash payments in the statement of cash flows.  The revised guidance is intended to reduce diversity in practice in how these items were being classified.  The new 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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Regulatory Matters

9 Months Ended

Sep. 30, 2016

Regulatory Matters

Regulatory Matters

Note 3— Regulatory Matters

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

Regulatory Assets and Liabilities

	September 30, 2016			December 31, 2015
Regulatory Assets:
Current:
Under recovered fuel costs	$	7		$	196
Current portion of long-term regulatory assets	7,120			6,856
Regulatory assets, current	7,127			7,052
Long-term:
Pension and other postretirement benefits(1)	101,307			108,273
Income taxes	48,581			48,613
Deferred construction accounting costs(2)	14,712			14,977
Unamortized loss on reacquired debt	9,226			9,731
Unsettled derivative losses — electric segment	3,323			7,775
System reliability — vegetation management	2,164			3,604
Storm costs	3,118			3,531
Asset retirement obligation	10,493			7,722
Customer programs	6,677			5,942
Missouri solar initiative(3)	10,897			3,504
Current portion of long-term regulatory assets	(7,120		)	(6,856		)
Unrecovered fuel costs	1,089			—
Other	2,687			2,892
Regulatory assets, long-term	207,154			209,708
Total Regulatory Assets	$	214,281		$	216,760
	September 30, 2016			December 31, 2015
Regulatory Liabilities:
Current:
Over recovered fuel costs	$	14,416		$	5,280
Current portion of long-term regulatory liabilities	3,308			3,335
Regulatory liabilities, current	17,724			8,615
Long-term:
Costs of removal(4)	98,265			94,193
SWPA payment for Ozark Beach lost generation	12,300			14,213
Income taxes	11,083			11,244
Deferred construction accounting costs — fuel(5)	7,574			7,690
Unamortized gain on interest rate derivative	2,904			3,031
Pension and other postretirement benefits	895			1,745
Over recovered fuel costs	2,065			2,300
System reliability — vegetation management	—			1,320
Current portion of long-term regulatory liabilities	(3,308		)	(3,335		)
Other	—			56
Regulatory liabilities, long-term	131,778			132,457
Total Regulatory Liabilities	$	149,502		$	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 841 solar rebate applications processed and internal costs as of September 30, 2016, (compared to 262 as of December 31, 2015), resulting in solar rebate-related costs totaling approximately $10.9 million.

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

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

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Risk Management and Derivative Financial Instruments

9 Months Ended

Sep. 30, 2016

Risk Management and Derivative Financial Instruments

Risk Management and Derivative Financial Instruments

Note 4— Risk Management and Derivative Financial Instruments

We engage in hedging activities in an effort to minimize our risk from the volatility of natural gas prices and power cost risk associated with exposure to congestion costs. We enter into both physical and financial contracts with counterparties relating to our future natural gas requirements that lock in prices (with respect to a range of predetermined percentages of our expected future natural gas needs) in an attempt to lessen the volatility in our fuel expenditures and gain cost 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 September 30, 2016 and December 31, 2015, we have recorded the following assets and liabilities representing the fair value of derivative financial instruments, (in thousands):

		September 30,		December 31,
ASSET DERIVATIVES		2016		2015
Hedging instruments	Balance Sheet Classification	Fair Value		Fair Value
Natural gas contracts, gas segment	Current assets	$	121	$	2
	Non-current assets and deferred charges - other	7		16
Natural gas contracts, electric segment	Current assets	1,039		—
	Non-current assets and deferred charges - other			—
Transmission congestion rights, electric segment	Current assets	3,367		1,293
Total derivatives assets		$	4,534	$	1,311
		September 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	2,118		4,190
	Non-current liabilities and deferred credits	1,520		3,630
Total derivatives liabilities		$	3,638	$	8,168

Electric Segment

At September 30, 2016, approximately $1.1 million of unrealized net losses are applicable to natural gas financial instruments which will settle within the next twelve months.

The following tables set forth “mark-to-market” pre-tax gains/(losses) from non-designated derivative instruments for the electric segment for each of the periods ended September 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						Nine Months Ended						Twelve Months Ended
Electric Segment	Derivative	2016			2015			2016			2015			2016			2015
Commodity contracts	Regulatory (assets)/liabilities	$	(1,678	)	$	(1,690	)	$	1,705		$	(3,909	)	$	(1,240	)	$	(10,152	)
Transmission congestion rights	Regulatory (assets)/liabilities	398			125			5,939			4,750			6,158			6,322
Total Electric Segment		$	(1,280	)	$	(1,565	)	$	7,644		$	841		$	4,918		$	(3,830	)
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						Nine Months Ended						Twelve Months Ended
Electric Segment	Derivative	2016			2015			2016			2015			2016			2015
Commodity contracts	Fuel and purchased power expense	$	(2,231	)	$	(4,104	)	$	(3,774	)	$	(6,381	)	$	(5,508	)	$	(7,105	)
Transmission congestion rights	Fuel and purchased power expense	1,468			1,133			3,811			6,446			4,833			8,653
Total Electric Segment		$	(763	)	$	(2,971	)	$	37		$	65		$	(675	)	$	1,548

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 September 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	33	%	—	1,160,000	$	3.122	Up to 100%
2017	41	%	782,900	5,210,000	$	3.347	60%
2018	20	%	565,000	2,460,000	$	3.334	40%
2019	10	%	—	1,460,000	$	2.955	20%
2020	0	%	—	—	$	—	10%

At September 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	Estimated Fair Value
2016-17	8,464	$	3,367

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 September 30, 2016, we had 1.8 million Dths in storage on the three pipelines that serve our customers. This represents 86% 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 September 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	—	1,751	65	%
Nov. 2017 – Mar. 2018	Up to 50%	280	—	—	9	%
Nov. 2018 – Mar. 2019	Up to 20%	0	—	—	0	%

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 September 30, (in thousands).

Non-Designated Hedging	Balance Sheet Classification of	Amount of Gain/(Loss) Recognized on Balance Sheet
Instruments Due to Regulatory	Gain / (Loss) on	Three Months Ended						Nine Months Ended					Twelve Months Ended
Accounting - Gas Segment	Derivative	2016			2015			2016		2015			2016			2015
Commodity contracts	Regulatory (assets)/liabilities	$	(65	)	$	(236	)	$	107	$	(50	)	$	(289	)	$	(647	)
Total - Gas Segment		$	(65	)	$	(236	)	$	107	$	(50	)	$	(289	)	$	(647	)

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 September 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)	September 30, 2016		December 31, 2015
Margin deposit assets	$	4.2	$	11.2

Offsetting of derivative assets and liabilities

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

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

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Fair Value Measurements

9 Months Ended

Sep. 30, 2016

Fair Value Measurements

Fair Value Measurements

Note 5— Fair Value Measurements

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

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

Our TCR positions, which are acquired on the SPP IM, are valued using the most recent monthly auction clearing prices. Our commodity contracts are valued using the market value approach on a recurring basis. The following fair value hierarchy table presents information about our TCR and commodity contracts measured at fair value as of September 30, 2016 and December 31, 2015.

	Fair Value Measurements at Reporting Date Using
($ in 000’s) Description	Assets/(Liabilities) at Fair Value			Quoted Prices in Active Markets for Identical Assets/(Liabilities) (Level 1)			Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
September 30, 2016
Derivative assets	$	4,534		$	1,167		$	3,367	$	—
Derivative liabilities	$	(3,638	)	$	(3,638	)	$	—	$	—
December 31, 2015
Derivative assets	$	1,311		$	18		$	1,293	$	—
Derivative liabilities	$	(8,168	)	$	(8,168	)	$	—	$	—

*The only recurring measurements are derivative related.

Other fair value considerations

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

The carrying amount of our total long-term debt exclusive of capital leases at both September 30, 2016 and December 31, 2015 was $851 million. The fair market value at September 30, 2016 was approximately $910 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 September 30, 2016 or that will be realizable in the future.

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Financing

9 Months Ended

Sep. 30, 2016

Financing

Financing

Note 6— Financing

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

The credit facility requires our total indebtedness to be less than 65.0% of our total capitalization at the end of each fiscal quarter and a failure to maintain this ratio will result in an event of default under the credit facility and will prohibit us from borrowing funds thereunder. As of September 30, 2016, we were in compliance with this covenant as our ratio of total indebtedness was 51% 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 September 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. As of September 30, 2016, there were no outstanding borrowings under either the credit agreement or our commercial paper program which the credit agreement backs.

On October 20, 2016, the revolving credit facility was amended such that the pending Merger would not trigger the credit agreement’s change of control provision. The revolving credit facility will remain in place after the Merger closing.

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Commitments and Contingencies

9 Months Ended

Sep. 30, 2016

Commitments and Contingencies

Commitments and Contingencies

Note 7— Commitments and Contingencies

Legal Proceedings

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

Proceedings in connection with the pending merger with Liberty Central

On March 24, 2016, a purported shareholder of Empire filed a complaint styled as a class action lawsuit in the District Court for the 3rd Judicial District, in Shawnee County, Kansas. The 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 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 and 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 and the parties anticipate this will take place after the closing of the Merger. 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 September 30, 2016 (in millions).

	Firm physical gas and transportation contracts		Coal and coal transportation contracts
October 1, 2016 through December 31, 2016	$	4.2	$	1.6
January 1, 2017 through December 31, 2018	37.4		14.5
January 1, 2019 through December 31, 2020	28.8		2.2
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 September 30, 2016, are detailed in the table above. Our existing railroad agreement was modified and became effective on October 1, 2016. Our contractual obligations, as reflected in the table above, were reduced as a result of the amendment. The amended terms continue to allow us to operate the Asbury plant up to full load capacity.

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 $270.1 million through August 31, 2039, the end date of the agreement.

We have a long-term purchased power agreement, which expires in 2028, with Cloud County Windfarm, LLC, 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 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 September 30, 2016 were $167.8 million for the project to date, excluding AFUDC. Final costs are estimated to range from $167.8 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 September 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:

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 from defenders and challengers of the climate rule were heard before a ten-judge panel on September 27, 2016. The D.C. court is expected to decide the case by late February 2017. If, however, the case is appealed to the Supreme Court, the matter is likely to continue into 2018.

Other than the cancellation of the initial submittal deadline in September 2016, 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 at our Asbury plant is expected to require the closure of the existing ash impoundment, construction of a new utility waste landfill and conversion of the existing bottom ash handling from a wet to a dry system. 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 MDNR has issued a draft construction permit, and approval of the final permit for the utility waste landfill is expected by February 2017.

At this time, we anticipate CCR/ELG compliance costs to be approximately $15-$30 million. This estimate is based on our current capital budget, information gathered to date in relation to the multiple CCR Rule reports, and the current execution plan. As we move forward through the ELG and CCR rules’ timelines of compliance, these plans may change. Currently, the landfill construction and bottom ash conversion are anticipated to be complete by early 2019. The CCR impoundment will be closed within five years after inactivity. 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 September 30, 2016, we had processed 841 solar rebate applications resulting in solar rebate-related costs totaling approximately $10.9 million under the new tariff. We have recorded the $10.9 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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Retirement and Other Employee Benefits

9 Months Ended

Sep. 30, 2016

Retirement and Other Employee Benefits

Retirement and Other Employee Benefits

Note 8 — Retirement and Other Employee Benefits

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

	Three months ended September 30,
	Pension Benefits						SERP						OPEB
	2016			2015			2016			2015			2016			2015
Service cost	$	1,752		$	1,816		$	41		$	33		$	826		$	945
Interest cost	2,669			2,702			110			102			1,188			1,175
Expected return on plan assets	(3,387		)	(3,396		)	—			—			(1,375		)	(1,272		)
Amortization of prior service cost (1)	(157		)	(157		)	(4		)	(10		)	(253		)	(253		)
Amortization of net actuarial loss (1)	2,313			2,835			149			168			326			699
Net periodic benefit cost	$	3,190		$	3,800		$	296		$	293		$	712		$	1,294

	Nine months ended September 30,
	Pension Benefits						SERP						OPEB
	2016			2015			2016			2015			2016			2015
Service cost	$	5,650		$	5,581		$	132		$	119		$	2,453		$	2,785
Interest cost	7,936			7,708			325			286			3,501			3,502
Expected return on plan assets	(10,318		)	(10,175		)	—			—			(4,124		)	(3,897		)
Amortization of prior service cost (1)	(472		)	(472		)	(11		)	(32		)	(758		)	(758		)
Amortization of net actuarial loss (1)	6,526			7,525			427			448			841			2,061
Net periodic benefit cost	$	9,322		$	10,167		$	873		$	821		$	1,913		$	3,693

	Twelve months ended September 30,
	Pension Benefits						SERP						OPEB
	2016			2015			2016			2015			2016			2015
Service cost	$	7,511		$	7,198		$	171		$	157		$	3,382		$	3,435
Interest cost	10,505			10,413			421			383			4,668			4,592
Expected return on plan assets	(13,709		)	(13,452		)	—			—			(5,423		)	(5,097		)
Amortization of prior service cost (1)	(630		)	(368		)	(21		)	(34		)	(1,011		)	(1,011		)
Amortization of net actuarial loss (1)	9,034			9,178			576			574			1,528			2,303
Net periodic benefit cost	$	12,711		$	12,969		$	1,147		$	1,080		$	3,144		$	4,222

(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 received 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 have made contributions totaling $12.5 million through the nine months ended September 30, 2016. No additional contributions are expected for the remainder of the year. 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 $1.8 million as of September 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 September 30, 2016, there were 707,735 shares available for issuance in this plan.

	2016		2015
Subscriptions outstanding at September 30	25,118		59,463
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.

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Equity Compensation

9 Months Ended

Sep. 30, 2016

Equity Compensation

Equity Compensation

Note 9 — Equity Compensation

Our time-vested restricted stock awards and performance-based restricted stock awards are valued as liability awards, in accordance with fair value guidelines. We allow qualified individuals to elect to have taxes in excess of the minimum statutory requirements withheld from their awards and, therefore, the awards are classified as liability instruments under the ASC guidance on share based payment. Awards treated as liability instruments must be revalued each period until settled, and cost is accrued over the requisite service period and adjusted to fair value at each reporting period until settlement or expiration of the award. Grants were made in the first quarter of 2016 (the effect of which is included in the table below). We had unrecognized compensation expense of $1.8 million as of September 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 September 30 (in thousands):

	Three Months Ended				Nine Months Ended				Twelve Months Ended
	2016		2015		2016		2015		2016		2015
Compensation Expense	$	1,302	$	598	$	4,211	$	1,659	$	6,832	$	2,976
Tax Benefit Recognized	485		213		1,565		592		2,549		1,081

Time-Vested Restricted Stock Awards

Our time-vested restricted stock awards vest after a three-year period. No dividend rights accumulate during the vesting period. Time-vested restricted stock is valued at an amount equal to the fair market value of our common stock on the date of grant. If employment terminates during the vesting period because of death, retirement, or disability, the participant is entitled to a pro-rata portion of the time-vested restricted stock awards such participant would otherwise have earned, which is distributed following the date of termination, with the remainder of the award forfeited. If employment is terminated during the vesting period for reasons other than those listed above, the time-vested restricted stock awards will be forfeited on the date of the termination, unless the Board of Directors Compensation Committee determines, in its sole discretion, that the participant is entitled to a pro-rata portion of the award. In addition, if a change in control occurs during the vesting period, a pro-rata portion of the time-vested restricted stock awards will vest upon such change in control, and any portion of such awards that remains unvested immediately after the change in control will be forfeited. Consummation of the Merger will constitute a change of control.

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 September 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 September 30, 2016 and 2015 and changes during the nine months ended September 30, 2016 and 2015 were as follows:

	2016				2015
			Weighted				Weighted
	Number of		Average Grant		Number 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 September 30,	66,788		$	27.22	69,021		$	24.38

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Regulated Operating Expense

9 Months Ended

Sep. 30, 2016

Regulated Operating Expense

Regulated Operating Expense

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 September 30 (in thousands):

	Three Months Ended		Three Months Ended		Nine Months Ended		Nine Months Ended		Twelve Months Ended		Twelve Months Ended
	2016		2015		2016		2015		2016		2015
Electric transmission and distribution expense	$	5,340	$	7,325	$	18,802	$	21,839	$	25,856	$	28,619
Natural gas transmission and distribution expense	610		592		1,933		1,997		2,635		2,558
Power operation expense (other than fuel)	4,466		4,258		12,505		13,813		16,955		17,708
Customer accounts and assistance expense	2,712		2,649		8,252		8,142		11,047		10,889
Employee pension expense (1)	3,574		2,769		8,843		8,170		11,459		10,797
Employee healthcare expense (1)	2,691		3,022		7,373		7,640		9,895		9,970
General office supplies and expense	4,157		3,352		12,434		9,032		17,840		13,591
Administrative and general expense	2,935		3,650		10,594		11,647		13,810		15,061
Allowance for uncollectible accounts	651		705		1,530		2,050		1,560		2,453
Miscellaneous expense	88		115		288		326		392		448
Total	$	27,224	$	28,437	$	82,554	$	84,656	$	111,449	$	112,094

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

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Segment Information

9 Months Ended

Sep. 30, 2016

Segment Information

Segment Information

Note 11— Segment Information

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

	For the three months ended September 30, 2016
($-000’s)	Electric		Gas			Other		Eliminations			Total
Statement of Income Information
Revenues	$	169,070	$	4,559		$	2,070	$	(345	)	$	175,354
Depreciation and amortization	22,365		1,009			478		—			23,852
Federal and state income taxes	17,065		(420		)	325		—			16,970
Operating income	38,250		249			515		—			39,014
Interest income	25		5			26		(30		)	26
Interest expense	10,668		967			—		(30		)	11,605
Income from AFUDC (debt and equity)	369		5			—		—			374
Net income	27,691		(714		)	528		—			27,505
Capital Expenditures	$	23,715	$	1,261		$	104	—			$	25,080

	For the three months ended September 30, 2015
($-000’s)	Electric		Gas			Other		Eliminations			Total
Statement of Income Information
Revenues	$	162,412	$	5,084		$	2,563	$	(345	)	$	169,714
Depreciation and amortization	18,651		984			455		—			20,090
Federal and state income taxes	15,137		(340		)	467		—			15,264
Operating income	34,622		413			748		—			35,783
Interest income	1		6			12		(17		)	2
Interest expense	10,384		968			—		(17		)	11,335
Income from AFUDC (debt and equity)	1,997		3			—		—			2,000
Net income	25,086		(560		)	759		—			25,285
Capital Expenditures	$	39,867	$	2,009		$	470				$	42,346

	For the nine months ended September 30, 2016
($-000’s)	Electric		Gas		Other		Eliminations			Total
Statement of Income Information
Revenues	$	435,256	$	25,313	$	6,455	$	(1,034	)	$	465,990
Depreciation and amortization	60,599		3,010		1,464		—			65,073
Federal and state income taxes	30,293		57		934		—			31,284
Operating income	77,195		2,977		1,462		—			81,634
Interest income	69		30		75		(94		)	80
Interest expense	32,054		2,903		—		(94		)	34,863
Income from AFUDC (debt and equity)	4,798		11		—		—			4,809
Net income	49,139		81		1,519		—			50,739
Capital Expenditures	$	86,366	$	3,264	$	682				$	90,312

	For the nine months ended September 30, 2015
($-000’s)	Electric		Gas		Other		Eliminations			Total
Statement of Income Information
Revenues	$	431,335	$	31,181	$	7,334	$	(1,035	)	$	468,815
Depreciation and amortization	55,930		2,932		1,375		—			60,237
Federal and state income taxes	26,296		454		1,326		—			28,076
Operating income	70,791		3,629		2,124		—			76,544
Interest income	128		34		33		(53		)	142
Interest expense	30,686		2,898		—		(53		)	33,531
Income from AFUDC (debt and equity)	5,493		6		—		—			5,499
Net income	43,809		728		2,155		—			46,692
Capital Expenditures	$	137,977	$	3,679	$	1,824				$	143,480

	For the twelve months ended September 30, 2016
($-000’s)	Electric		Gas		Other		Eliminations			Total
Statement of Income Information
Revenues	$	559,005	$	35,835	$	9,286	$	(1,379	)	$	602,747
Depreciation and amortization	79,402		4,001		1,983		—			85,386
Federal and state income taxes	35,121		403		1,497		—			37,021
Operating income	94,527		4,501		2,362		—			101,390
Interest income	74		32		90		(113		)	83
Interest expense	42,675		3,872		—		(113		)	46,434
Income from AFUDC (debt and equity)	6,987		18		—		—			7,005
Net income	57,569		641		2,434		—			60,644
Capital Expenditures	$	117,500	$	4,775	$	1,082				$	123,357

	For the twelve months ended September 30, 2015
($-000’s)	Electric		Gas		Other		Eliminations			Total
Statement of Income Information
Revenues	$	565,471	$	46,437	$	9,650	$	(1,379	)	$	620,179
Depreciation and amortization	72,971		3,902		1,901		—			78,774
Federal and state income taxes	31,894		1,230		1,689		—			34,813
Operating income	87,188		5,859		2,798		—			95,845
Interest income	131		36		40		(62		)	145
Interest expense	40,352		3,865		—		(62		)	44,155
Income from AFUDC (debt and equity)	8,290		11		—		—			8,301
Net Income	53,005		1,981		2,818		—			57,804
Capital Expenditures	$	199,189	$	5,431	$	2,656				$	207,276

	As of September 30, 2016
($-000’s)	Electric		Gas(1)		Other		Eliminations			Total
Balance Sheet Information
Total assets	$	2,362,639	$	124,544	$	39,470	$	(50,096	)	$	2,476,557

(1) Includes goodwill of $39,492.

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

(1) Includes goodwill of $39,492.

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Income Taxes

9 Months Ended

Sep. 30, 2016

Income Taxes

Income Taxes

Note 12— Income Taxes

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

	Three Months Ended						Nine Months Ended						Twelve Months Ended
	2016			2015			2016			2015			2016			2015
Consolidated provision for income taxes	$	17.0		$	15.3		$	31.3		$	28.1		$	37.0		$	34.8
Consolidated effective federal and state income tax rates	38.2		%	37.6		%	38.1		%	37.6		%	37.9		%	37.6		%

The effective income tax rate for the three, nine and twelve month periods ended September 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 September 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 utilized $43.8 million of the 2014 tax NOLs on our 2015 return. We also anticipate incurring a $17.0 million NOL in 2016 mostly due to bonus depreciation we expect to utilize on our recently completed Riverton Combined Cycle Plant project. As of September 30, 2016, we estimate there are $12.4 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 2016 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.

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Mergers and Acquisitions

9 Months Ended

Sep. 30, 2016

Mergers and Acquisitions

Mergers and Acquisitions

Note 13 — Mergers and Acquisitions

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

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

The closing of the Merger is subject to certain conditions, including, among others, approval of Empire shareholders, expiration or termination of the applicable Hart-Scott-Rodino Act (HSR Act) 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. As discussed below, all approvals have been received except for approval from the KCC.

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 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.

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. We received an order on September 29, 2016 from the APSC approving the Merger.

On August 4, 2016, we filed a non-unanimous stipulation and agreement with the staff of the MPSC. On September 7, 2016, we received an order from the MPSC approving the Merger, effective October 7, 2016.

On October 6, 2016, we announced a filing with the KCC of a Unanimous Settlement Agreement with respect to the joint application for approval of the Merger filed March 16, 2016. The Unanimous Settlement Agreement is subject to approval by the KCC. As a condition of the Unanimous Settlement Agreement that was reached with the KCC staff, our pending Kansas rate case is to be withdrawn and current base rates are to remain in effect through January 1, 2019. A decision from Kansas regulators is due no later than January 10, 2017, with an expected transaction close early in 2017.

In connection with each of the regulatory agreements noted above, Liberty Utilities Co. has agreed to certain commitments regarding ongoing service to Empire customers, employment of Empire personnel, cost sharing mechanisms, and compliance with existing regulatory stipulations in the normal course of business.

In connection with entering into the Merger Agreement, Empire has incurred approximately $8.7 million of transaction costs as of September 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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Recently Issued and Proposed Accounting Standards (Policies)

9 Months Ended

Sep. 30, 2016

Recently Issued and Proposed Accounting Standards

Recently Issued and Proposed Accounting Standards

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 $8.1 million in unamortized debt issuance costs being reclassified from deferred charges to long-term debt on the September 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 liabilities, and cash flow classification. This guidance will be effective for periods beginning after December 15, 2016. The application of this standard is not expected to have a material impact on our results of operations, financial position or liquidity.

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.

Classification of Certain Cash Receipts and Cash Payments:  In August 2016 the FASB issued revised guidance addressing the classification of eight specific cash receipts and cash payments in the statement of cash flows.  The revised guidance is intended to reduce diversity in practice in how these items were being classified.  The new 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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Regulatory Matters (Tables)

9 Months Ended

Sep. 30, 2016

Regulatory Matters

Components of regulatory assets and liabilities

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

Regulatory Assets and Liabilities

	September 30, 2016			December 31, 2015
Regulatory Assets:
Current:
Under recovered fuel costs	$	7		$	196
Current portion of long-term regulatory assets	7,120			6,856
Regulatory assets, current	7,127			7,052
Long-term:
Pension and other postretirement benefits(1)	101,307			108,273
Income taxes	48,581			48,613
Deferred construction accounting costs(2)	14,712			14,977
Unamortized loss on reacquired debt	9,226			9,731
Unsettled derivative losses — electric segment	3,323			7,775
System reliability — vegetation management	2,164			3,604
Storm costs	3,118			3,531
Asset retirement obligation	10,493			7,722
Customer programs	6,677			5,942
Missouri solar initiative(3)	10,897			3,504
Current portion of long-term regulatory assets	(7,120		)	(6,856		)
Unrecovered fuel costs	1,089			—
Other	2,687			2,892
Regulatory assets, long-term	207,154			209,708
Total Regulatory Assets	$	214,281		$	216,760
	September 30, 2016			December 31, 2015
Regulatory Liabilities:
Current:
Over recovered fuel costs	$	14,416		$	5,280
Current portion of long-term regulatory liabilities	3,308			3,335
Regulatory liabilities, current	17,724			8,615
Long-term:
Costs of removal(4)	98,265			94,193
SWPA payment for Ozark Beach lost generation	12,300			14,213
Income taxes	11,083			11,244
Deferred construction accounting costs — fuel(5)	7,574			7,690
Unamortized gain on interest rate derivative	2,904			3,031
Pension and other postretirement benefits	895			1,745
Over recovered fuel costs	2,065			2,300
System reliability — vegetation management	—			1,320
Current portion of long-term regulatory liabilities	(3,308		)	(3,335		)
Other	—			56
Regulatory liabilities, long-term	131,778			132,457
Total Regulatory Liabilities	$	149,502		$	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 841 solar rebate applications processed and internal costs as of September 30, 2016, (compared to 262 as of December 31, 2015), resulting in solar rebate-related costs totaling approximately $10.9 million.

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

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

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Risk Management and Derivative Financial Instruments (Tables)

9 Months Ended

Sep. 30, 2016

Risk Management and Derivative Financial Instruments

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

As of September 30, 2016 and December 31, 2015, we have recorded the following assets and liabilities representing the fair value of derivative financial instruments, (in thousands):

		September 30,		December 31,
ASSET DERIVATIVES		2016		2015
Hedging instruments	Balance Sheet Classification	Fair Value		Fair Value
Natural gas contracts, gas segment	Current assets	$	121	$	2
	Non-current assets and deferred charges - other	7		16
Natural gas contracts, electric segment	Current assets	1,039		—
	Non-current assets and deferred charges - other			—
Transmission congestion rights, electric segment	Current assets	3,367		1,293
Total derivatives assets		$	4,534	$	1,311
		September 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	2,118		4,190
	Non-current liabilities and deferred credits	1,520		3,630
Total derivatives liabilities		$	3,638	$	8,168

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

The following tables set forth “mark-to-market” pre-tax gains/(losses) from non-designated derivative instruments for the electric segment for each of the periods ended September 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						Nine Months Ended						Twelve Months Ended
Electric Segment	Derivative	2016			2015			2016			2015			2016			2015
Commodity contracts	Regulatory (assets)/liabilities	$	(1,678	)	$	(1,690	)	$	1,705		$	(3,909	)	$	(1,240	)	$	(10,152	)
Transmission congestion rights	Regulatory (assets)/liabilities	398			125			5,939			4,750			6,158			6,322
Total Electric Segment		$	(1,280	)	$	(1,565	)	$	7,644		$	841		$	4,918		$	(3,830	)
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						Nine Months Ended						Twelve Months Ended
Electric Segment	Derivative	2016			2015			2016			2015			2016			2015
Commodity contracts	Fuel and purchased power expense	$	(2,231	)	$	(4,104	)	$	(3,774	)	$	(6,381	)	$	(5,508	)	$	(7,105	)
Transmission congestion rights	Fuel and purchased power expense	1,468			1,133			3,811			6,446			4,833			8,653
Total Electric Segment		$	(763	)	$	(2,971	)	$	37		$	65		$	(675	)	$	1,548

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

			Dth Hedged		Procurement
Year	% Hedged		Physical	Financial	Average Price		Guidelines
Remainder 2016	33	%	—	1,160,000	$	3.122	Up to 100%
2017	41	%	782,900	5,210,000	$	3.347	60%
2018	20	%	565,000	2,460,000	$	3.334	40%
2019	10	%	—	1,460,000	$	2.955	20%
2020	0	%	—	—	$	—	10%

Schedule of transmission congestion rights (TCR)

At September 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	Estimated Fair Value
2016-17	8,464	$	3,367

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

The following table sets forth our long-term hedge strategy of mitigating price volatility for our customers by hedging a minimum of expected gas usage for the current winter season and the next two winter seasons and illustrates our hedged position as of September 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	—	1,751	65	%
Nov. 2017 – Mar. 2018	Up to 50%	280	—	—	9	%
Nov. 2018 – Mar. 2019	Up to 20%	0	—	—	0	%

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

The following table sets forth “mark-to-market” pre-tax gains / (losses) from derivatives not designated as hedging instruments for the gas segment for each of the periods ended September 30, (in thousands).

Non-Designated Hedging	Balance Sheet Classification of	Amount of Gain/(Loss) Recognized on Balance Sheet
Instruments Due to Regulatory	Gain / (Loss) on	Three Months Ended						Nine Months Ended					Twelve Months Ended
Accounting - Gas Segment	Derivative	2016			2015			2016		2015			2016			2015
Commodity contracts	Regulatory (assets)/liabilities	$	(65	)	$	(236	)	$	107	$	(50	)	$	(289	)	$	(647	)
Total - Gas Segment		$	(65	)	$	(236	)	$	107	$	(50	)	$	(289	)	$	(647	)

Schedule of margin deposit assets

(in millions)	September 30, 2016		December 31, 2015
Margin deposit assets	$	4.2	$	11.2

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Fair Value Measurements (Tables)

9 Months Ended

Sep. 30, 2016

Fair Value Measurements

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

	Fair Value Measurements at Reporting Date Using
($ in 000’s) Description	Assets/(Liabilities) at Fair Value			Quoted Prices in Active Markets for Identical Assets/(Liabilities) (Level 1)			Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
September 30, 2016
Derivative assets	$	4,534		$	1,167		$	3,367	$	—
Derivative liabilities	$	(3,638	)	$	(3,638	)	$	—	$	—
December 31, 2015
Derivative assets	$	1,311		$	18		$	1,293	$	—
Derivative liabilities	$	(8,168	)	$	(8,168	)	$	—	$	—

*The only recurring measurements are derivative related.

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Commitments and Contingencies (Tables)

9 Months Ended

Sep. 30, 2016

Commitments and Contingencies

Schedule of physical gas, coal and transportation contracts

The following table sets forth our firm physical gas, coal and transportation contracts for the periods indicated as of September 30, 2016 (in millions).

	Firm physical gas and transportation contracts		Coal and coal transportation contracts
October 1, 2016 through December 31, 2016	$	4.2	$	1.6
January 1, 2017 through December 31, 2018	37.4		14.5
January 1, 2019 through December 31, 2020	28.8		2.2
January 1, 2021 and beyond	45.7		—

Summary of most significant environmental regulations affecting operations

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

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Retirement and Other Employee Benefits (Tables)

9 Months Ended

Sep. 30, 2016

Retirement and Other Employee Benefits

Schedule of net periodic benefit pension cost

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

	Three months ended September 30,
	Pension Benefits						SERP						OPEB
	2016			2015			2016			2015			2016			2015
Service cost	$	1,752		$	1,816		$	41		$	33		$	826		$	945
Interest cost	2,669			2,702			110			102			1,188			1,175
Expected return on plan assets	(3,387		)	(3,396		)	—			—			(1,375		)	(1,272		)
Amortization of prior service cost (1)	(157		)	(157		)	(4		)	(10		)	(253		)	(253		)
Amortization of net actuarial loss (1)	2,313			2,835			149			168			326			699
Net periodic benefit cost	$	3,190		$	3,800		$	296		$	293		$	712		$	1,294

	Nine months ended September 30,
	Pension Benefits						SERP						OPEB
	2016			2015			2016			2015			2016			2015
Service cost	$	5,650		$	5,581		$	132		$	119		$	2,453		$	2,785
Interest cost	7,936			7,708			325			286			3,501			3,502
Expected return on plan assets	(10,318		)	(10,175		)	—			—			(4,124		)	(3,897		)
Amortization of prior service cost (1)	(472		)	(472		)	(11		)	(32		)	(758		)	(758		)
Amortization of net actuarial loss (1)	6,526			7,525			427			448			841			2,061
Net periodic benefit cost	$	9,322		$	10,167		$	873		$	821		$	1,913		$	3,693

	Twelve months ended September 30,
	Pension Benefits						SERP						OPEB
	2016			2015			2016			2015			2016			2015
Service cost	$	7,511		$	7,198		$	171		$	157		$	3,382		$	3,435
Interest cost	10,505			10,413			421			383			4,668			4,592
Expected return on plan assets	(13,709		)	(13,452		)	—			—			(5,423		)	(5,097		)
Amortization of prior service cost (1)	(630		)	(368		)	(21		)	(34		)	(1,011		)	(1,011		)
Amortization of net actuarial loss (1)	9,034			9,178			576			574			1,528			2,303
Net periodic benefit cost	$	12,711		$	12,969		$	1,147		$	1,080		$	3,144		$	4,222

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

Schedule of employee stock purchase plan

	2016		2015
Subscriptions outstanding at September 30	25,118		59,463
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.

Schedule of assumptions used in valuation of shares under employee stock purchase plan

	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

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Equity Compensation (Tables)

9 Months Ended

Sep. 30, 2016

Equity Compensation

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

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

	Three Months Ended				Nine Months Ended				Twelve Months Ended
	2016		2015		2016		2015		2016		2015
Compensation Expense	$	1,302	$	598	$	4,211	$	1,659	$	6,832	$	2,976
Tax Benefit Recognized	485		213		1,565		592		2,549		1,081

Schedule of time vested restricted stock activity

	2016				2015
			Weighted				Weighted
	Number of		Average Grant		Number of		Average Grant
	shares		Date Fair Value		shares		Date Fair Value
Outstanding at January 1,	55,600		$	24.60	41,000		$	21.89
Granted	18,400		29.53		19,000		30.40
Distributed	(18,500	)	21.36		(1,654	)	21.92
Forfeited shares	0				(2,746	)	25.91
Outstanding at September 30	55,500		$	27.31	55,600		$	24.60

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

	2016				2015
			Weighted				Weighted
	Number of		Average Grant		Number 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 September 30,	66,788		$	27.22	69,021		$	24.38

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Regulated Operating Expense (Tables)

9 Months Ended

Sep. 30, 2016

Regulated Operating Expense

Schedule of regulated operating expenses

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

	Three Months Ended		Three Months Ended		Nine Months Ended		Nine Months Ended		Twelve Months Ended		Twelve Months Ended
	2016		2015		2016		2015		2016		2015
Electric transmission and distribution expense	$	5,340	$	7,325	$	18,802	$	21,839	$	25,856	$	28,619
Natural gas transmission and distribution expense	610		592		1,933		1,997		2,635		2,558
Power operation expense (other than fuel)	4,466		4,258		12,505		13,813		16,955		17,708
Customer accounts and assistance expense	2,712		2,649		8,252		8,142		11,047		10,889
Employee pension expense (1)	3,574		2,769		8,843		8,170		11,459		10,797
Employee healthcare expense (1)	2,691		3,022		7,373		7,640		9,895		9,970
General office supplies and expense	4,157		3,352		12,434		9,032		17,840		13,591
Administrative and general expense	2,935		3,650		10,594		11,647		13,810		15,061
Allowance for uncollectible accounts	651		705		1,530		2,050		1,560		2,453
Miscellaneous expense	88		115		288		326		392		448
Total	$	27,224	$	28,437	$	82,554	$	84,656	$	111,449	$	112,094

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

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Segment Information (Tables)

9 Months Ended

Sep. 30, 2016

Segment Information

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

	For the three months ended September 30, 2016
($-000’s)	Electric		Gas			Other		Eliminations			Total
Statement of Income Information
Revenues	$	169,070	$	4,559		$	2,070	$	(345	)	$	175,354
Depreciation and amortization	22,365		1,009			478		—			23,852
Federal and state income taxes	17,065		(420		)	325		—			16,970
Operating income	38,250		249			515		—			39,014
Interest income	25		5			26		(30		)	26
Interest expense	10,668		967			—		(30		)	11,605
Income from AFUDC (debt and equity)	369		5			—		—			374
Net income	27,691		(714		)	528		—			27,505
Capital Expenditures	$	23,715	$	1,261		$	104	—			$	25,080

	For the three months ended September 30, 2015
($-000’s)	Electric		Gas			Other		Eliminations			Total
Statement of Income Information
Revenues	$	162,412	$	5,084		$	2,563	$	(345	)	$	169,714
Depreciation and amortization	18,651		984			455		—			20,090
Federal and state income taxes	15,137		(340		)	467		—			15,264
Operating income	34,622		413			748		—			35,783
Interest income	1		6			12		(17		)	2
Interest expense	10,384		968			—		(17		)	11,335
Income from AFUDC (debt and equity)	1,997		3			—		—			2,000
Net income	25,086		(560		)	759		—			25,285
Capital Expenditures	$	39,867	$	2,009		$	470				$	42,346

	For the nine months ended September 30, 2016
($-000’s)	Electric		Gas		Other		Eliminations			Total
Statement of Income Information
Revenues	$	435,256	$	25,313	$	6,455	$	(1,034	)	$	465,990
Depreciation and amortization	60,599		3,010		1,464		—			65,073
Federal and state income taxes	30,293		57		934		—			31,284
Operating income	77,195		2,977		1,462		—			81,634
Interest income	69		30		75		(94		)	80
Interest expense	32,054		2,903		—		(94		)	34,863
Income from AFUDC (debt and equity)	4,798		11		—		—			4,809
Net income	49,139		81		1,519		—			50,739
Capital Expenditures	$	86,366	$	3,264	$	682				$	90,312

	For the nine months ended September 30, 2015
($-000’s)	Electric		Gas		Other		Eliminations			Total
Statement of Income Information
Revenues	$	431,335	$	31,181	$	7,334	$	(1,035	)	$	468,815
Depreciation and amortization	55,930		2,932		1,375		—			60,237
Federal and state income taxes	26,296		454		1,326		—			28,076
Operating income	70,791		3,629		2,124		—			76,544
Interest income	128		34		33		(53		)	142
Interest expense	30,686		2,898		—		(53		)	33,531
Income from AFUDC (debt and equity)	5,493		6		—		—			5,499
Net income	43,809		728		2,155		—			46,692
Capital Expenditures	$	137,977	$	3,679	$	1,824				$	143,480

	For the twelve months ended September 30, 2016
($-000’s)	Electric		Gas		Other		Eliminations			Total
Statement of Income Information
Revenues	$	559,005	$	35,835	$	9,286	$	(1,379	)	$	602,747
Depreciation and amortization	79,402		4,001		1,983		—			85,386
Federal and state income taxes	35,121		403		1,497		—			37,021
Operating income	94,527		4,501		2,362		—			101,390
Interest income	74		32		90		(113		)	83
Interest expense	42,675		3,872		—		(113		)	46,434
Income from AFUDC (debt and equity)	6,987		18		—		—			7,005
Net income	57,569		641		2,434		—			60,644
Capital Expenditures	$	117,500	$	4,775	$	1,082				$	123,357

	For the twelve months ended September 30, 2015
($-000’s)	Electric		Gas		Other		Eliminations			Total
Statement of Income Information
Revenues	$	565,471	$	46,437	$	9,650	$	(1,379	)	$	620,179
Depreciation and amortization	72,971		3,902		1,901		—			78,774
Federal and state income taxes	31,894		1,230		1,689		—			34,813
Operating income	87,188		5,859		2,798		—			95,845
Interest income	131		36		40		(62		)	145
Interest expense	40,352		3,865		—		(62		)	44,155
Income from AFUDC (debt and equity)	8,290		11		—		—			8,301
Net Income	53,005		1,981		2,818		—			57,804
Capital Expenditures	$	199,189	$	5,431	$	2,656				$	207,276

	As of September 30, 2016
($-000’s)	Electric		Gas(1)		Other		Eliminations			Total
Balance Sheet Information
Total assets	$	2,362,639	$	124,544	$	39,470	$	(50,096	)	$	2,476,557

(1) Includes goodwill of $39,492.

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

(1) Includes goodwill of $39,492.

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Income Taxes (Tables)

9 Months Ended

Sep. 30, 2016

Income Taxes

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

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

	Three Months Ended						Nine Months Ended						Twelve Months Ended
	2016			2015			2016			2015			2016			2015
Consolidated provision for income taxes	$	17.0		$	15.3		$	31.3		$	28.1		$	37.0		$	34.8
Consolidated effective federal and state income tax rates	38.2		%	37.6		%	38.1		%	37.6		%	37.9		%	37.6		%

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Summary of Significant Accounting Policies (Details)	9 Months Ended
	Sep. 30, 2016 segment item
Accounting Policies
Number of business segments | segment	3
Number of towns to which water service is provided	3
Number of communities provided natural gas distribution	48

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Recently Issued and Proposed Accounting Standards (Details) - USD ($) $ in Millions	9 Months Ended	12 Months Ended
	Sep. 30, 2016	Dec. 31, 2015
Scenario, Adjustment | Accounting Standards Update 2015-03 Simplifying the Presentation of Debt Issuance Costs
Recently Issued and Proposed Accounting Standards
Change in financial position	$ 8.1	$ 8.7

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Regulatory Matters (Details) $ in Thousands	9 Months Ended	12 Months Ended
	Sep. 30, 2016 USD ($) item	Dec. 31, 2015 USD ($) item
Regulatory Assets:
Regulatory assets, current	$ 7,127	$ 7,052
Regulatory assets, long-term	207,154	209,708
Total Regulatory Assets	214,281	216,760
Regulatory Liabilities:
Regulatory liabilities, current	17,724	8,615
Regulatory liabilities, long-term	131,778	132,457
Total Regulatory Liabilities	149,502	141,072
Over recovered fuel costs
Regulatory Liabilities:
Regulatory liabilities, current	14,416	5,280
Regulatory liabilities, long-term	2,065	2,300
System reliability - vegetation management
Regulatory Liabilities:
Regulatory liabilities, long-term		1,320
Current portion of long-term regulatory liabilities
Regulatory Liabilities:
Regulatory liabilities, current	3,308	3,335
Other
Regulatory Liabilities:
Regulatory liabilities, long-term		56
Costs of removal
Regulatory Liabilities:
Regulatory liabilities, long-term	98,265	94,193
SWPA payment for Ozark Beach lost generation
Regulatory Liabilities:
Regulatory liabilities, long-term	12,300	14,213
Income taxes
Regulatory Liabilities:
Regulatory liabilities, long-term	11,083	11,244
Deferred construction accounting costs - fuel
Regulatory Liabilities:
Regulatory liabilities, long-term	7,574	7,690
Unamortized gain on interest rate derivative
Regulatory Liabilities:
Regulatory liabilities, long-term	2,904	3,031
Pension and other postretirement benefits
Regulatory Liabilities:
Regulatory liabilities, long-term	895	1,745
Under recovered fuel costs
Regulatory Assets:
Regulatory assets, current	7	196
Current portion of long-term regulatory assets
Regulatory Assets:
Regulatory assets, current	7,120	6,856
Pension and other postretirement benefits
Regulatory Assets:
Regulatory assets, long-term	101,307	108,273
Income taxes
Regulatory Assets:
Regulatory assets, long-term	48,581	48,613
Deferred construction accounting costs
Regulatory Assets:
Regulatory assets, long-term	14,712	14,977
Unamortized loss on reacquired debt
Regulatory Assets:
Regulatory assets, long-term	9,226	9,731
System reliability - vegetation management
Regulatory Assets:
Regulatory assets, long-term	2,164	3,604
Storm costs
Regulatory Assets:
Regulatory assets, long-term	3,118	3,531
Asset retirement obligation.
Regulatory Assets:
Regulatory assets, long-term	10,493	7,722
Customer programs
Regulatory Assets:
Regulatory assets, long-term	6,677	5,942
Missouri solar initiative
Regulatory Assets:
Regulatory assets, long-term	$ 10,897	$ 3,504
Number of solar rebate applications processed | item	841	262
Unrecovered fuel costs
Regulatory Assets:
Regulatory assets, long-term	$ 1,089
Other
Regulatory Assets:
Regulatory assets, long-term	2,687	$ 2,892
Electric | Unsettled derivative losses- electric segment
Regulatory Assets:
Regulatory assets, long-term	$ 3,323	$ 7,775

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Risk Management and Derivative Financial Instruments - Fair Value (Details) - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
Fair value of derivative financial instruments
Current assets	$ 4,527	$ 1,295
Non-current assets and deferred charges - other	7	16
Total derivatives assets	4,534	1,311
Current liabilities	2,118	4,472
Non-current liabilities and deferred credits	1,520	3,696
Total derivatives liabilities	3,638	8,168
Hedging instruments | Commodity contracts | Gas
Fair value of derivative financial instruments
Current assets	121	2
Non-current assets and deferred charges - other	7	16
Current liabilities		282
Non-current liabilities and deferred credits		66
Hedging instruments | Commodity contracts | Electric
Fair value of derivative financial instruments
Current assets	1,039
Current liabilities	2,118	4,190
Non-current liabilities and deferred credits	1,520	3,630
Hedging instruments | Transmission congestion rights (TCR) | Electric
Fair value of derivative financial instruments
Current assets	$ 3,367	$ 1,293

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Risk Management and Derivative Financial Instruments - Gain Loss on Derivatives (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Electric
Gain / (Loss) on derivatives
Unrealized net gains applicable to financial instruments which will settle in next twelve months	$ 1,100		$ 1,100		$ 1,100
Period within which financial instruments will settle			12 months
Amount of Gain/(Loss) Recognized on Balance Sheet	(1,280)	$ (1,565)	$ 7,644	$ 841	4,918	$ (3,830)
Amount of Gain / (Loss) Recognized in Income on Derivative	(763)	(2,971)	37	65	(675)	1,548
Gas
Gain / (Loss) on derivatives
Amount of Gain/(Loss) Recognized on Balance Sheet	(65)	(236)	107	(50)	(289)	(647)
Commodity contracts | Electric
Gain / (Loss) on derivatives
Amount of Gain/(Loss) Recognized on Balance Sheet	(1,678)	(1,690)	1,705	(3,909)	(1,240)	(10,152)
Amount of Gain / (Loss) Recognized in Income on Derivative	(2,231)	(4,104)	(3,774)	(6,381)	(5,508)	(7,105)
Commodity contracts | Gas
Gain / (Loss) on derivatives
Amount of Gain/(Loss) Recognized on Balance Sheet	(65)	(236)	107	(50)	(289)	(647)
Transmission congestion rights (TCR) | Electric
Gain / (Loss) on derivatives
Amount of Gain/(Loss) Recognized on Balance Sheet	398	125	5,939	4,750	6,158	6,322
Amount of Gain / (Loss) Recognized in Income on Derivative	$ 1,468	$ 1,133	$ 3,811	$ 6,446	$ 4,833	$ 8,653

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Risk Management and Derivative Financial Instruments - Derivatives Hedging Strategy (Details) $ in Thousands	9 Months Ended
	Sep. 30, 2016 USD ($) item MWh $ / item
Transmission congestion rights (TCR) - 2015
Procurement guidelines
Monthly MWH Hedged | MWh	8,464.0
Monthly MWH Hedged, estimated fair value | $	$ 3,367
Electric | Natural Gas Usage - Remainder 2016
Volumes and percentage of anticipated volume of natural gas usage
% Hedged	33.00%
Dth Hedged Financial	1,160,000
Average Price (in dollars per dth) | $ / item	3.122
Electric | Natural Gas Usage - 2017
Volumes and percentage of anticipated volume of natural gas usage
% Hedged	41.00%
Dth Hedged Physical	782,900
Dth Hedged Financial	5,210,000
Average Price (in dollars per dth) | $ / item	3.347
Electric | Natural Gas Usage - 2018
Volumes and percentage of anticipated volume of natural gas usage
% Hedged	20.00%
Dth Hedged Physical	565,000
Dth Hedged Financial	2,460,000
Average Price (in dollars per dth) | $ / item	3.334
Electric | Natural Gas Forward 2019
Volumes and percentage of anticipated volume of natural gas usage
% Hedged	10.00%
Dth Hedged Financial	1,460,000
Average Price (in dollars per dth) | $ / item	2.995
Electric | Natural Gas Forward 2020
Volumes and percentage of anticipated volume of natural gas usage
% Hedged	0.00%
Electric | Current Year Procurement Guidelines
Procurement guidelines
Maximum percentage of volume to be hedged in any given month	100.00%
Maximum flexibility to hedge any future year's expected requirements (as a percent)	80.00%
Electric | First Year Procurement Guidelines
Volumes and percentage of anticipated volume of natural gas usage
% Hedged	60.00%
Electric | Second Year Procurement Guidelines
Volumes and percentage of anticipated volume of natural gas usage
% Hedged	40.00%
Electric | Third Year Procurement Guidelines
Volumes and percentage of anticipated volume of natural gas usage
% Hedged	20.00%
Electric | Fourth Year Procurement Guidelines
Volumes and percentage of anticipated volume of natural gas usage
% Hedged	10.00%
Electric | High end of range | Current Year Procurement Guidelines
Volumes and percentage of anticipated volume of natural gas usage
% Hedged	100.00%

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Risk Management and Derivative Financial Instruments - Other (Details) $ in Millions	9 Months Ended
	Sep. 30, 2016 USD ($) item	Dec. 31, 2015 USD ($)
Contingent Features
Derivative instruments with the credit-risk-related contingent features that are in a liability position | $	$ 0.0
Collateral posted | $	0.0
Margin deposit liabilities | $	0.0
Margin deposit assets
Margin deposit assets | $	$ 4.2	$ 11.2
Gas
Price Risk Mitigation for Gas Segment
Target percentage of storage capacity utilization	95.00%
Volume of storage in pipelines that serve customers (in Dth)	1,800,000
Number of pipelines that serve customers (in units)	3
Storage capacity utilized (as a percent)	86.00%
Number of future winter seasons for which minimum of expected gas usage is hedged (in seasons)	2
Gas | Nov. 2016 - Mar. 2017
Gas Usage Hedged By Winter Season
Target % Hedged	50.00%
Dth Hedged Financial	200
Dth in Storage	1,751
Actual % Hedged	65.00%
Gas | High end of range | Nov. 2017 - Mar. 2018
Gas Usage Hedged By Winter Season
Target % Hedged	50.00%
Dth Hedged Financial	280
Actual % Hedged	9.00%
Gas | High end of range | Nov. 2018 - Mar. 2019
Gas Usage Hedged By Winter Season
Target % Hedged	20.00%
Dth Hedged Financial	0
Actual % Hedged	0.00%

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Fair Value Measurements - Hierarchy (Details) - Recurring basis - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
Fair Value Measurements at Reporting Date
Derivative assets	$ 4,534	$ 1,311
Derivative liabilities	(3,638)	(8,168)
Quoted Prices in Active Markets for Identical Assets/(Liabilities) (Level 1)
Fair Value Measurements at Reporting Date
Derivative assets	1,167	18
Derivative liabilities	(3,638)	(8,168)
Significant Other Observable Inputs (Level 2)
Fair Value Measurements at Reporting Date
Derivative assets	$ 3,367	$ 1,293

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Fair Value Measurements - Long Term Debt (Details) - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015
Long-Term Debt
Carrying amount of total long-term debt exclusive of capital leases	$ 851	$ 851
Fair market value	$ 910	$ 815

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Financing (Details) $ in Millions	9 Months Ended
	Sep. 30, 2016 USD ($) item
Schedule of debt instruments
Outstanding borrowings	$ 0
Unsecured revolving credit facility
Schedule of debt instruments
Unsecured revolving credit facility	200
Additional borrowing capacity	$ 75
Number of extensions | item	2
Extension period	1 year
Maximum percentage of total indebtedness to total capitalization under the financial covenants of the credit facility agreement	65.00%
Percentage of total indebtedness to total capitalization under the financial covenants of the credit facility agreement	51.00%
Aggregate amount of default on other indebtedness subject to cross-default under the terms of the credit facility.	$ 25
Swingline loan
Schedule of debt instruments
Unsecured revolving credit facility	20
Letters of credit
Schedule of debt instruments
Unsecured revolving credit facility	$ 20

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Commitments and Contingencies - Other (Detail) $ in Millions			9 Months Ended
	Dec. 15, 2008	Dec. 15, 2005	Sep. 30, 2016 USD ($) Office item MW
Electric | Power Plant Mercury And Air Toxics Rule
Commitments and Contingencies
Cost related to pre-engineering, site preparation activities and contract cost project to date			$ 167.8
Term of Capital Expenditure Plan			5 years
Electric | Low end of range | Power Plant Mercury And Air Toxics Rule
Commitments and Contingencies
Estimated project cost			$ 167.8
Electric | High end of range | Power Plant Mercury And Air Toxics Rule
Commitments and Contingencies
Estimated project cost			175.0
Firm Physical gas and transportation contracts
Commitments and Contingencies
October 1, 2016 through December 31, 2016			4.2
January 1, 2017 through December 31, 2018			37.4
January 1, 2019 through December 31, 2020			28.8
January 1, 2021 and beyond			45.7
Coal and coal transportation contracts
Commitments and Contingencies
October 1, 2016 through December 31, 2016			1.6
January 1, 2017 through December 31, 2018			14.5
January 1, 2019 through December 31, 2020			$ 2.2
Purchased power
Commitments and Contingencies
Number of purchased power agreement | item			3
Purchased power | Plum Point Energy Station
Commitments and Contingencies
Energy capacity (in megawatts) | MW			670
Amount of energy capacity owned (in megawatts) | MW			50
Additional capacity under long-term contract agreement (in megawatts) | MW			50
Amount of long-term contract obligation			$ 270.1
Purchased power | Cloud County Windfarm
Commitments and Contingencies
Energy capacity (in megawatts) | MW			105
Period of the average cost that is used as a basis for determining the maximum annual payments	20 years
Purchased power | Cloud County Windfarm | Low end of range
Commitments and Contingencies
Amount of annual payments contingent upon output of the facility			$ 0.0
Purchased power | Cloud County Windfarm | High end of range
Commitments and Contingencies
Amount of annual payments contingent upon output of the facility			$ 14.6
Purchased power | Elk River Windfarm
Commitments and Contingencies
Energy capacity (in megawatts) | MW			150
Period of the average cost that is used as a basis for determining the maximum annual payments		20 years
Purchased power | Elk River Windfarm | Low end of range
Commitments and Contingencies
Amount of annual payments contingent upon output of the facility			$ 0.0
Purchased power | Elk River Windfarm | High end of range
Commitments and Contingencies
Amount of annual payments contingent upon output of the facility			16.9
Leases
Commitments and Contingencies
Gross amount of assets recorded under capital leases			$ 5.3
Leases | Electric
Commitments and Contingencies
Number of unit trains under short-term operating leases | item			2
Leases | Gas
Commitments and Contingencies
Number of office facilities under short-term operating leases | Office			1
Leases | Plum Point Energy Station
Commitments and Contingencies
Number of railcars under capital leases | item			108

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Commitments and Contingencies - Regulations (Details) $ in Thousands		9 Months Ended
	Jan. 09, 2016 state	Sep. 30, 2016 USD ($) item	Dec. 31, 2015 USD ($)
Environmental Laws And Regulations
Regulatory assets of Missouri solar initiative		$ 207,154	$ 209,708
Surface Impoundments | Asbury Power Plant | Electric
Environmental Laws And Regulations
Asset retirement obligation		$ 5,400
CRR impound will be closed after inactivity		5 years
Surface Impoundments | Asbury Power Plant | Electric | High end of range
Environmental Laws And Regulations
Compliance costs		$ 30,000
Surface Impoundments | Asbury Power Plant | Electric | Low end of range
Environmental Laws And Regulations
Compliance costs		15,000
Surface Impoundments | Iatan | Electric
Environmental Laws And Regulations
Asset retirement obligation		$ 4,400
Renewable Energy | Electric
Environmental Laws And Regulations
Minimum percentage of Missouri retail sales required to generate or purchase electricity in 2014-2017		5.00%
Minimum percentage of Missouri retail sales required to generate or purchase electricity by 2018-2020		10.00%
Minimum percentage of Missouri retail sales required to generate or purchase electricity by 2021		15.00%
Percentage of Missouri retail sales required to generate or purchase solar energy		2.00%
Number of solar rebate applications processed in Missouri solar initiative | item		841
Rebate Commitments in Missouri solar initiative		$ 10,900
Regulatory assets of Missouri solar initiative		$ 10,900
Percentage of Kansas retail customer peak capacity required to be sourced from renewable energy by 2020		20.00%
Green House Gases
Environmental Laws And Regulations
Percentage of carbon emission reduction from 2005 baseline levels by 2030, required by the proposed Clean Power Plan		32.00%
Number of plan types for states to choose to meet their goals | item		2
Clean Power Plan
Environmental Laws And Regulations
Number of states initiating legal challenges to invalidate rule | state	27

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Retirement and Other Employee Benefits (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2016	Sep. 30, 2016	Sep. 30, 2015
Pension Benefits
Net Periodic Pension Benefit Cost:
Service cost	$ 1,752	$ 1,816	$ 5,650	$ 5,581		$ 7,511	$ 7,198
Interest cost	2,669	2,702	7,936	7,708		10,505	10,413
Expected return on plan assets	(3,387)	(3,396)	(10,318)	(10,175)		(13,709)	(13,452)
Amortization of prior service cost	(157)	(157)	(472)	(472)		(630)	(368)
Amortization of net actuarial loss	2,313	2,835	6,526	7,525		9,034	9,178
Net periodic benefit cost	3,190	3,800	9,322	10,167		12,711	12,969
Employer contribution			12,500
SERP
Net Periodic Pension Benefit Cost:
Service cost	41	33	132	119		171	157
Interest cost	110	102	325	286		421	383
Amortization of prior service cost	(4)	(10)	(11)	(32)		(21)	(34)
Amortization of net actuarial loss	149	168	427	448		576	574
Net periodic benefit cost	296	293	873	821		1,147	1,080
OPEB
Net Periodic Pension Benefit Cost:
Service cost	826	945	2,453	2,785		3,382	3,435
Interest cost	1,188	1,175	3,501	3,502		4,668	4,592
Expected return on plan assets	(1,375)	(1,272)	(4,124)	(3,897)		(5,423)	(5,097)
Amortization of prior service cost	(253)	(253)	(758)	(758)		(1,011)	(1,011)
Amortization of net actuarial loss	326	699	841	2,061		1,528	2,303
Net periodic benefit cost	$ 712	$ 1,294	1,913	$ 3,693		$ 3,144	$ 4,222
Pension contributions					$ 2,600
Employer contribution			$ 1,800
Healthcare benefits
Net Periodic Pension Benefit Cost:
Eligible age			55 years
Minimum service period for eligibility			5 years

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Retirement and Other Employee Benefits - Employee Stock Purchase Plan (Details) - Employee Stock Purchase Plan - $ / shares	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015
Actual return on plan assets:
Common stock purchase price to eligible employees (as a percent)	90.00%
Percentage of Black-Scholes methodology used as a component to calculate value of lookback feature	90.00%
Percentage of maximum subscription price used as a component to calculate value of lookback feature	10.00%
Shares available for issuance	707,735
Subscriptions outstanding (in shares)	25,118	59,463
Maximum subscription price (in dollars per share)	$ 30.29	$ 21.43
Shares of stock issued	56,908	56,193
Stock issuance price (in dollars per share)	$ 21.09	$ 21.01
Assumptions for valuation of shares
Fair value of grants (in dollars per share)	$ 6.11	$ 3.58
Risk-free interest rate (as a percent)	0.70%	0.26%
Expected dividend yield (as a percent)	3.10%	4.40%
Expected volatility (as a percent)	27.00%	21.00%
Expected life in months	12 months	12 months

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Equity Compensation - Share Based Compensation (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Dec. 31, 2015	Sep. 30, 2015
Other Equity Compensation
Unrecognized compensation expense	$ 1,800		$ 1,800		$ 1,800
Compensation Expense	1,302	$ 598	4,211	$ 1,659	6,832		$ 2,976
Tax Benefit Recognized	$ 485	$ 213	$ 1,565	$ 592	$ 2,549		$ 1,081
Time-Vested Restricted Stock Awards
Assumptions used for estimating fair value of grants outstanding
Vesting period			3 years
Changes in restricted stock awards
Nonvested, balance at the beginning of the period (in shares)			55,600	41,000	55,600	41,000
Granted (in shares)			18,400	19,000
Distributed (in shares)			(18,500)	(1,654)
Forfeited shares (in shares)			0	(2,746)
Nonvested, balance at the end of the period (in shares)	55,500	55,600	55,500	55,600	55,500	55,600	55,600
Weighted Average Grant Date Fair Value
Nonvested, balance at the beginning of the period (in dollars per share)			$ 24.60	$ 21.89	$ 24.60	$ 21.89
Granted (in dollars per share)			29.53	30.40
Distributed (in dollars per share)			21.36	21.92
Forfeited shares ( in dollars per share)						25.91
Nonvested, balance at the end of the period (in dollars per share)	$ 27.31	$ 24.60	$ 27.31	$ 24.60	$ 27.31	$ 24.60	$ 24.60
Performance-Based Restricted Stock Awards
Changes in restricted stock awards
Nonvested, balance at the beginning of the period (in shares)			69,021	63,300	69,021	63,300
Target shares granted (in shares)			22,400	21,800
Shares issued in excess of target (in shares)			18,403	3,653
Shares awarded (in shares)			(43,036)	(13,653)
Forfeited shares (in shares)				(6,079)
Nonvested, balance at the end of the period (in shares)	66,788	69,021	66,788	69,021	66,788	69,021	69,021
Weighted Average Grant Date Fair Value
Nonvested, balance at the beginning of the period (in dollars per share)			$ 24.38	$ 21.74	$ 24.38	$ 21.74
Target shares granted (in dollars per share)			$ 29.53	$ 30.40
Shares issued in excess of target (in dollars per share)			21.36	30.55
Shares awarded (in dollars per share)			$ 21.36	$ 30.55
Forfeited shares ( in dollars per share)				24.10
Nonvested, balance at the end of the period (in dollars per share)	$ 27.22	$ 24.38	$ 27.22	$ 24.38	$ 27.22	$ 24.38	$ 24.38

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Regulated Operating Expenses (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Regulated Operating Expense
Electric transmission and distribution expense	$ 5,340	$ 7,325	$ 18,802	$ 21,839	$ 25,856	$ 28,619
Natural gas transmission and distribution expense	610	592	1,933	1,997	2,635	2,558
Power operation expense (other than fuel)	4,466	4,258	12,505	13,813	16,955	17,708
Customer accounts and assistance expense	2,712	2,649	8,252	8,142	11,047	10,889
Employee pension expense	3,574	2,769	8,843	8,170	11,459	10,797
Employee healthcare expense	2,691	3,022	7,373	7,640	9,895	9,970
General office supplies and expense	4,157	3,352	12,434	9,032	17,840	13,591
Administrative and general expense	2,935	3,650	10,594	11,647	13,810	15,061
Allowance for uncollectible accounts	651	705	1,530	2,050	1,560	2,453
Miscellaneous expense	88	115	288	326	392	448
Total	$ 27,224	$ 28,437	$ 82,554	$ 84,656	$ 111,449	$ 112,094

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Segment Information (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Statement of Income Information, balance sheet information and capital expenditures of business segments
Operating Revenues	$ 175,354	$ 169,714	$ 465,990	$ 468,815	$ 602,747	$ 620,179
Depreciation and amortization	23,852	20,090	65,073	60,237	85,386	78,774
Federal and state income taxes	16,970	15,264	31,284	28,076	37,021	34,813
Operating income	39,014	35,783	81,634	76,544	101,390	95,845
Interest income	26	2	80	142	83	145
Interest expense	11,605	11,335	34,863	33,531	46,434	44,155
Income from AFUDC (debt and equity)	374	2,000	4,809	5,499	7,005	8,301
Net income	27,505	25,285	50,739	46,692	60,644	57,804
Capital Expenditures	25,080	42,346	90,312	143,480	123,357	207,276
Total assets	2,476,557		2,476,557		2,476,557		$ 2,446,645
Goodwill	39,492		39,492		39,492		39,492
Operating segments | Electric
Statement of Income Information, balance sheet information and capital expenditures of business segments
Operating Revenues	169,070	162,412	435,256	431,335	559,005	565,471
Depreciation and amortization	22,365	18,651	60,599	55,930	79,402	72,971
Federal and state income taxes	17,065	15,137	30,293	26,296	35,121	31,894
Operating income	38,250	34,622	77,195	70,791	94,527	87,188
Interest income	25	1	69	128	74	131
Interest expense	10,668	10,384	32,054	30,686	42,675	40,352
Income from AFUDC (debt and equity)	369	1,997	4,798	5,493	6,987	8,290
Net income	27,691	25,086	49,139	43,809	57,569	53,005
Capital Expenditures	23,715	39,867	86,366	137,977	117,500	199,189
Total assets	2,362,639		2,362,639		2,362,639		2,331,705
Operating segments | Gas
Statement of Income Information, balance sheet information and capital expenditures of business segments
Operating Revenues	4,559	5,084	25,313	31,181	35,835	46,437
Depreciation and amortization	1,009	984	3,010	2,932	4,001	3,902
Federal and state income taxes	(420)	(340)	57	454	403	1,230
Operating income	249	413	2,977	3,629	4,501	5,859
Interest income	5	6	30	34	32	36
Interest expense	967	968	2,903	2,898	3,872	3,865
Income from AFUDC (debt and equity)	5	3	11	6	18	11
Net income	(714)	(560)	81	728	641	1,981
Capital Expenditures	1,261	2,009	3,264	3,679	4,775	5,431
Total assets	124,544		124,544		124,544		127,359
Goodwill	39,492		39,492		39,492		39,492
Operating segments | Other
Statement of Income Information, balance sheet information and capital expenditures of business segments
Operating Revenues	2,070	2,563	6,455	7,334	9,286	9,650
Depreciation and amortization	478	455	1,464	1,375	1,983	1,901
Federal and state income taxes	325	467	934	1,326	1,497	1,689
Operating income	515	748	1,462	2,124	2,362	2,798
Interest income	26	12	75	33	90	40
Net income	528	759	1,519	2,155	2,434	2,818
Capital Expenditures	104	470	682	1,824	1,082	2,656
Total assets	39,470		39,470		39,470		38,299
Eliminations
Statement of Income Information, balance sheet information and capital expenditures of business segments
Operating Revenues	(345)	(345)	(1,034)	(1,035)	(1,379)	(1,379)
Interest income	(30)	(17)	(94)	(53)	(113)	(62)
Interest expense	(30)	$ (17)	(94)	$ (53)	(113)	$ (62)
Total assets	$ (50,096)		$ (50,096)		$ (50,096)		$ (50,718)

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Income Taxes (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2014	Dec. 31, 2010
Income Taxes
Consolidated provision for income taxes	$ 16,970	$ 15,264	$ 31,284	$ 28,076	$ 37,021	$ 34,813
Consolidated effective federal and state income tax rates (as a percent)	38.20%	37.60%	38.10%	37.60%	37.90%	37.60%
Net operating loss	$ 17,000		$ 17,000		$ 17,000		$ 74,100
Deferred tax assets							43,800
Deferred tax assets estimated to be utilized	$ 12,400		$ 12,400		$ 12,400
Advanced coal investment tax credit								$ 17,700
Maximum tax credit utilized							$ 9,000

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Mergers and Acquisitions (Details)				3 Months Ended	9 Months Ended	12 Months Ended
	Jun. 29, 2016	Mar. 16, 2016 item	Feb. 09, 2016 USD ($)	Sep. 30, 2016 USD ($)	Sep. 30, 2016 USD ($)	Dec. 31, 2016 USD ($)	Sep. 30, 2016 USD ($)
Mergers and Acquisitions
Maximum period for extending regulatory approvals			6 months
Maximum period for exercising termination right			9 months
Termination fee			$ 53,000,000
Number of States to which Entity Provides Electric Service | item		4
Transaction costs				$ 252,000	$ 8,691,000		$ 8,691,000
Waiting period	30 days
Liberty Utilities (Central) Co
Mergers and Acquisitions
Right to receive in cash without interest			34.00
Termination fee			$ 65,000,000
Forecast
Mergers and Acquisitions
Percentage payable of transaction costs						50.00%
Forecast | High end of range
Mergers and Acquisitions
Transaction costs						$ 17,000,000
Forecast | Low end of range
Mergers and Acquisitions
Transaction costs						$ 15,000,000