Exhibit 99.1

FORM 51-102F4

BUSINESS ACQUISITION REPORT

Item 1 Identity of Company

1.1 Name and Address of Company

Algonquin Power & Utilities Corp. (“Algonquin” orthe “Company”)

354 Davis Road

Oakville, Ontario, L6J 2X1

1.2 Executive Officer

The following executive officer of the Company is knowledgeable about the significant acquisition and this report:

David Bronicheski

Chief Financial Officer

(905) 465-4512

Item 2 Details of Acquisition

2.1 Nature of Business Acquired

Based in Joplin, Missouri, The Empire District Electric Company (“Empire”) is a regulated utility providing electric, natural gas (through its wholly-owned subsidiary The Empire District Gas Company) and water service in Missouri, Kansas, Oklahoma, and Arkansas.

The vertically-integrated regulated electricity operations of Empire represent the majority of its operating revenues and assets. For the year ended December 31, 2016, approximately 93% of Empire’s revenues were attributable to its electricity operations, with approximately 6% of revenues attributable to its natural gas subsidiary, and approximately 1% attributable to its fiber optics business.

Empire’s electric operations cover a service territory of approximately 10,000 square miles, located principally in southwestern Missouri, and also include smaller areas in southeastern Kansas, northeastern Oklahoma and northwestern Arkansas. Empire supplies electric service to customers in 119 incorporated communities and to various unincorporated areas and at wholesale to four municipally-owned distribution systems. The largest urban area served is the city of Joplin, Missouri, and its immediate vicinity, with a population of approximately 160,000. As of December 31, 2016, Empire’s electric operations served approximately 171,400 customers.

Empire’s gas operations serve customers in northwest, north central and west central Missouri. As of December 31, 2016, the gas operations served approximately 43,500 customers. Empire provided natural gas distribution to 48 communities and 434 transportation customers as of December 31, 2016. The largest urban area served by Empire’s gas operations is the city of Sedalia with a population of over 20,000.

Empire’s operating revenue in fiscal years 2016 and 2015 totalled approximately US$612.5 million and US$605.5 million respectively. As of December 31, 2016, Empire had total assets of approximatelyUS$2.7 billion.

2.2 Acquisition Date

Liberty Utilities Co. (“Liberty Utilities”), Algonquin's wholly-owned regulated utility business, completed the acquisition (the “Acquisition”) of Empire on January 1, 2017.

2.3 Consideration

Pursuant to the agreement and plan of merger dated February 9, 2016 between Liberty Utilities (Central) Co., Liberty Sub Corp. and Empire, upon the closing of the Transaction, each issued and outstanding share of Empire common stock was cancelled and converted automatically into the right to receive US$34.00 in cash (the “Cash Payment”) which, including the assumption of approximately US$0.9 billion of debt at closing, represents an aggregate purchase price of approximately US$2.4 billion paid by the Company.

The approximately US$1.5 billion Cash Payment was financed at the time of closing of the Acquisition with a combination of: (i) the net proceeds of the first instalment payment from a public offering of 5.00% convertible unsecured subordinated debentures (“Debentures”) of Algonquin (the “Offering”); and (ii) amounts drawn under the Acquisition Credit Facility (as defined below).

The Offering

In the first quarter of 2016, the Company and its direct wholly-owned subsidiary, Liberty Utilities (Canada) Corp., entered into an agreement with a syndicate of underwriters, under which the underwriters agreed to buy, on a bought deal basis, $1.15 billion aggregate principal amount of Debentures. The Debentures were sold to the public on an instalment basis at a price of Cdn$1,000 principal amount debenture, of which Cdn$333 was received on closing of the Offering (“First Instalment”) and the remaining Cdn$667 (the “Final Instalment”) was paid on February 2, 2017 following the closing of the Acquisition.

The net proceeds received from the First Instalment were approximately Cdn$357.7 million and the net proceeds received from the Final Instalment were approximately Cdn$744.1 million.

The Acquisition Credit Facility

On February 9, 2016, in connection with the Acquisition, the Company obtained, from a syndicate of banks, a non-revolving unsecured term credit facility in favour of Algonquin (the “Acquisition Credit Facility”) in an aggregate amount of US$1.6 billion (subsequently reduced to US$1.3 billion). On December 30, 2016 the Company drew the full amount available under the Acquisition Credit Facility and transferred such funds to a paying agent for purposes of paying the Cash Payment.

A portion of the outstanding indebtedness under the Acquisition Credit Facility was subsequentlyrepaid with the net proceeds received from the Final Instalment.  On March 1, 2017 Liberty Utilities Co., Algonquin's regulated distribution utility holding company, entered into an agreement to issue US$750.0 million of senior unsecured private placement notes.  The closing of

the offering is expected to occur prior to the end of March, 2017 and a portion of the proceeds are expected to be used to repay the remaining balance of the Acquisition Credit Facility.

2.4 Effect on Financial Position

The Company does not have any current plans for material changes in its business affairs or the affairs of Empire which may have a significant effect on the results of operations and financial position of the Company.

2.5 Prior Valuations

Not applicable.

2.6 Parties to Transaction

The Acquisition was not with an “informed person” (as such term is defined in Section 1.1 of National Instrument 51-102 – Continuous Disclosure Obligations), associate or affiliate of the Company.

2.7 Date of Report

March 10, 2017.

Item 3 Financial Statements and Other Information

The following financial statements are attached this report as Schedule “A” and Schedule “B”, respectively, and form part of this report:

(a) the audited annual consolidated financial statements of Empire, as at December 31, 2016 and 2015, and the related consolidated statement of income, statement of common stockholders’ equity, and statement of cash flows for the three years ended December 31, 2016, including the notes thereto and auditor’s report thereon; and

(b) the unaudited pro forma consolidated financial statements, including the foreword and the notes thereto, as at December 31, 2016 and the for the year then ended.

SCHEDULE A

Independent Auditors Report

To the Management of

The Empire District Electric Company

We have audited the accompanying consolidated financial statements of The Empire District Electric Company and its subsidiaries, which comprise the consolidated balance sheets as of December 31, 2016 and December 31, 2015, and the related consolidated statements of income, statements of common stockholders’ equity, and statements of cash flows for the three years ended December 31, 2016.

Management's Responsibility for the Consolidated Financial Statements

Management is responsible for the preparation and fair presentation of the consolidated financial statements in accordance with accounting principles generally accepted in the United States of America; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.

Auditors’ Responsibility

Our responsibility is to express an opinion on the consolidated financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on our judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, we consider internal control relevant to the Company's preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of The Empire District Electric Company and its subsidiaries as of December 31, 2016 and December 31, 2015, and the results of its operations and its cash flows for the three years ended December 31, 2016, in accordance with accounting principles generally accepted in the United States of America.

February 15, 2017

PricewaterhouseCoopers LLP, 800 Market Street, St. Louis, MO 63101

T: (314) 206 8500, F: (314) 206 8514, www.pwc.com/us

THE EMPIRE DISTRICT ELECTRIC COMPANY

Consolidated Balance Sheets

	December 31,
	2016		2015
Assets	($-000’s)
Plant and property, at original cost:
Electric	$	2,726,264	$	2,473,927
Gas		87,071		83,402
Other		45,181		44,263
Construction work in progress		29,022		183,689
		2,887,538		2,785,281
Accumulated depreciation and amortization		823,287		764,895
		2,064,251		2,020,386
Current assets:
Cash and cash equivalents		1,742		1,753
Restricted cash		4,728		4,726
Accounts receivable – trade, net of allowance of $460 and $623, respectively		43,859		40,162
Accrued unbilled revenues		24,997		20,653
Accounts receivable – other		4,063		28,320
Fuel, materials and supplies		56,047		60,950
Prepaid expenses and other		9,894		9,125
Unrealized gain in fair value of derivative contracts		6,041		1,295
Regulatory assets		8,390		7,052
		159,761		174,036
Noncurrent assets and deferred charges:
Regulatory assets		212,085		209,708
Goodwill		39,492		39,492
Unrealized gain in fair value of derivative contracts		684		16
Other		3,008		3,007
		255,269		252,223
Total assets	$	2,479,281	$	2,446,645

(Continued)

The accompanying notes are an integral part of these consolidated financial statements.

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THE EMPIRE DISTRICT ELECTRIC COMPANY

Consolidated Balance Sheets

	December 31,
	2016		2015
Capitalization and liabilities	($-000’s)
Common stock, $1 par value, 100,000,000 shares authorized, 44,177,535 and 43,820,726 shares issued and outstanding, respectively	$	44,178	$	43,821
Capital in excess of par value		667,953		657,466
Retained earnings		115,766		101,443
Total common stockholders’ equity		827,897		802,730
Long-term debt (net of current portion)
Obligations under capital lease		3,250		3,580
First mortgage bonds and secured debt		725,472		724,838
Unsecured debt		100,993		100,935
Total long-term debt		829,715		829,353
Total long-term debt and common stockholders’ equity		1,657,612		1,632,083
Current liabilities:
Accounts payable and accrued liabilities		53,941		66,946
Current maturities of long-term debt		329		25,246
Short-term debt		24,750		25,000
Regulatory liabilities		14,506		8,615
Customer deposits		15,440		14,623
Interest accrued		7,198		7,348
Unrealized loss in fair value of derivative contracts		1,143		4,472
Taxes accrued		3,176		2,832
Dividends declared		3,896		-
Other current liabilities		220		323
		124,599		155,405
Commitments and contingencies (Note 11)
Noncurrent liabilities and deferred credits:
Regulatory liabilities		136,024		132,457
Deferred income taxes		429,666		396,542
Unamortized investment tax credits		18,077		18,487
Pension and other postemployment benefit obligations		78,272		82,144
Unrealized loss in fair value of derivative contracts		1,239		3,696
Other		33,792		25,831
Total capitalization and liabilities		697,070		659,157
	$	2,479,281	$	2,446,645

The accompanying notes are an integral part of these consolidated financial statements.

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THE EMPIRE DISTRICT ELECTRIC COMPANY

Consolidated Statements of Income

	Year Ended December 31,
	2016			2015			2014
	(000’s, except per share amounts)
Operating revenues:
Electric	$	568,766		$	555,085		$	592,491
Gas		36,743			41,702			51,842
Other		7,041			8,786			7,997
Operating revenue deductions:		612,550			605,573			652,330
Fuel and purchased power		154,430			169,860			215,086
Cost of natural gas sold and transported		15,180			19,502			27,025
Regulated operating expenses		114,129			113,551			110,691
Other operating expenses		3,254			3,309			2,987
Maintenance and repairs		46,530			48,522			46,775
Merger related expenses		9,082			-			-
Loss on plant disallowance		-			-			86
Depreciation and amortization		86,006			80,550			73,185
Provision for income taxes		39,601			34,800			39,398
Other taxes		37,918			39,178			37,098
		506,130			509,272			552,331
Operating income		106,420			96,301			99,999
Other income and (deductions):
Allowance for equity funds used during construction		3,208			4,850			6,420
Interest income		130			145			51
Benefit for other income taxes		496			988			178
Other – non-operating expense, net		(1,857	)		(3,429	)		(1,302	)
		1,977			2,554			5,347
Interest charges:
Long-term debt		45,038			43,802			40,637
Short-term debt		120			266			113
Allowance for borrowed funds used during construction		(1,928	)		(2,845	)		(3,497	)
Other		1,140			1,035			990
		44,370			42,258			38,243
Net income	$	64,027		$	56,597		$	67,103
Weighted average number of common shares outstanding - basic		44,000			43,671			43,291
Weighted average number of common shares outstanding - diluted		44,066			43,718			43,314
Total earnings per weighted average share of common stock – basic	$	1.46		$	1.30		$	1.55
Total earnings per weighted average share of common stock -Diluted	$	1.45		$	1.29		$	1.55
Dividends declared per share of common stock	$	1.129		$	1.04		$	1.025

The accompanying notes are an integral part of these consolidated financial statements.

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THE EMPIRE DISTRICT ELECTRIC COMPANY

Consolidated Statements of Common Stockholders’ Equity

	Common Stock		Capital in Excess of Par		Retained Earnings			Total
	($-000’s)
Balance at December 31, 2013		43,044		639,525		67,554			750,123
Net income						67,103			67,103
Stock/stock units issued through:
Stock purchase and reinvestment plans		435		10,018					10,453
Dividends declared						(44,381	)		(44,381	)
Balance at December 31, 2014		43,479		649,543		90,276			783,298
Net income						56,597			56,597
Stock/stock units issued through:
Stock purchase and reinvestment plans		342		7,923					8,265
Dividends declared						(45,430	)		(45,430	)
Balance at December 31, 2015		43,821		657,466		101,443			802,730
Net income						64,027			64,027
Stock/stock units issued through:
Stock purchase and reinvestment plans		357		10,487					10,844
Dividends declared						(49,704	)		(49,704	)
Balance at December 31, 2016	$	44,178	$	667,953	$	115,766		$	827,897

The accompanying notes are an integral part of these consolidated financial statements.

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THE EMPIRE DISTRICT ELECTRIC COMPANY

Consolidated Statements of Cash Flows

	Year Ended December 31,
	2016			2015			2014
Operating activities:				($-000’s)
Net income	$	64,027		$	56,597		$	67,103
Adjustments to reconcile net income to cash flows from operating activities:
Depreciation and amortization including regulatory items		83,723			88,801			82,754
Pension and other postemployment benefit costs, net of contributions		1,946			(9,184	)		1,973
Deferred income taxes and unamortized investment tax credit, net		38,366			36,617			41,693
Allowance for equity funds used during construction		(3,208	)		(4,850	)		(6,420	)
Stock compensation expense		6,448			4,082			4,057
Loss on plant disallowance		-			-			86
Non-cash loss on derivatives		2,428			6,994			1,245
Other		95			(625	)		44
Cash flows impacted by changes in:
Accounts receivable and accrued unbilled revenues		7,296			16,514			(24,174	)
Fuel, materials and supplies		4,903			(3,151	)		(8,121	)
Prepaid expenses, other current assets and deferred charges		(18,190	)		(4,863	)		(6,051	)
Accounts payable and accrued liabilities		(13,552	)		(8,630	)		1,141
Asset retirement obligation		(384	)		(73	)		(1,326	)
Interest, taxes accrued and customer deposits		1,011			1,111			1,411
Other liabilities and other deferred credits		11,374			5,492			(4,192	)
Net cash provided by operating activities		186,283			184,832			151,223

(Continued)

The accompanying notes are an integral part of these consolidated financial statements.

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THE EMPIRE DISTRICT ELECTRIC COMPANY

Consolidated Statements of Cash Flows

	Year Ended December 31,
	2016			2015			2014
Investing activities:				($-000’s)
Capital expenditures – regulated	$	(121,462	)	$	(183,206	)	$	(211,429	)
Capital expenditures and other investments – non-regulated		(938	)		(2,243	)		(1,998	)
Restricted cash		(2	)		-			(1,854	)
Total net cash used in investing activities		(122,402	)		(185,449	)		(215,281	)
Financing activities:
Proceeds from first mortgage bonds, net		-			60,000			60,000
Long-term debt issuance costs		-			(818	)		(651	)
Repayment of first mortgage bonds		(25,000	)		-			-
Proceeds from issuance of common stock, net of issuance costs		7,476			5,513			7,994
Net short-term borrowings (repayments)		(250	)		(19,000	)		40,000
Dividends		(45,808	)		(45,430	)		(44,381	)
Other		(310	)		-			(274	)
Net cash provided by / (used) in financing activities		(63,892	)		265			62,688
Net decrease in cash and cash equivalents		(11	)		(352	)		(1,370	)
Cash and cash equivalents, beginning of year		1,753			2,105			3,475
Cash and cash equivalents, end of year	$	1,742		$	1,753		$	2,105

	2016			2015			2014
Supplemental cash flow information:
Interest paid	$	44,938		$	42,858		$	40,127
Income taxes (refunded) paid, net of refund		(7,441	)		(17,256	)		23,103
Supplementary non-cash investing activities:
Change in accrued additions to property, plant and equipment not reported above	$	(3,134	)	$	(8,924	)	$	9,427
Capital lease obligations for purchase of new equipment	$	-		$	17			-

The accompanying notes are an integral part of these consolidated financial statements.

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THE EMPIRE DISTRICT ELECTRIC COMPANY

Notes to Consolidated Financial Statements

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

General

Pursuant to an Agreement and Plan of Merger (“the Merger Agreement”), dated as of February 9, 2016, by and among The Empire District Electric Company (“Empire” or “EDE”), Liberty Utilities (Central) Co. (“Liberty Central”) (an indirect subsidiary of Algonquin Power & Utilities Corp. (“Algonquin” or “APUC”)) and Liberty Sub Corp. (“Merger Sub”), a wholly owned direct subsidiary of Liberty Central, Merger Sub merged with and into Empire, with Empire surviving the merger and becoming a wholly-owned direct subsidiary of Liberty Central (“the Merger”). The Merger closed effective January 1, 2017 (“the Closing Date”). As a result, effective with the closing of the Merger, Empire ceased to be a publically-held corporation and Empire common stock ceased trading on the New York Stock Exchange. (See Note 17 for further discussion of the Merger Agreement.)

We operate our businesses as three segments: electric, gas and other. Empire, 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 engaged in the distribution of natural gas in Missouri. Our other segment consists of our fiber optics business. See Note 12. Our gross operating revenues in 2016 were derived as follows:

Electric segment sales*			92.9	%
On-system revenues	86.6	%
SPP IM revenues	4.0
Other revenues	2.0
Gas segment sales			6.0
Other segment sales			1.1

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

The utility portions of our business are subject to regulation by the Missouri Public Service Commission (MPSC), the State Corporation Commission of the State of Kansas (KCC), the Corporation Commission of Oklahoma (OCC), the Arkansas Public Service Commission (APSC) and the Federal Energy Regulatory Commission (FERC). Our accounting policies are in accordance with the ratemaking practices of the regulatory authorities and conform to generally accepted accounting principles as applied to regulated public utilities.

Our electric operations serve approximately 171,400 customers as of December 31, 2016, and the 2016 electric operating revenues were derived as follows:

Customer Class	% of revenue
Residential		41.8	%
Commercial		30.4
Industrial		15.2
Wholesale on-system		3.5
Wholesale off-system		4.3
Miscellaneous sources, primarily public authorities		2.7
Other electric revenues		2.1

Our retail electric revenues for 2016 by jurisdiction were as follows:

Jurisdiction	% of revenue
Missouri		90.1	%
Kansas		4.4
Oklahoma		2.6
Arkansas		2.9

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THE EMPIRE DISTRICT ELECTRIC COMPANY

Notes to Consolidated Financial Statements

Our gas operations serve approximately 43,500 customers as of December 31, 2016, and the 2016 gas operating revenues were derived as follows:

Customer Class	% of revenue
Residential		63.0	%
Commercial		24.6
Industrial		0.7
Transportation		9.9
Miscellaneous		1.8

Basis of Presentation

The consolidated financial statements include the accounts of EDE, EDG, and our other subsidiaries. The consolidated entity is referred to throughout as “we” or the “Company”. All intercompany balances and transactions have been eliminated in consolidation. See Note 12 for additional information regarding our three segments. Certain immaterial reclassifications have been made to prior year information to conform to the current year presentation.

Use of Estimates

The preparation of financial statements in conformity with generally accepted accounting principles (GAAP) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements. Estimates also affect the reported amounts of revenues and expenses during the period. Areas in the financial statements significantly affected by estimates and assumptions include unbilled utility revenues, collectability of accounts receivable, depreciable lives, asset impairment and goodwill impairment evaluations, employee benefit obligations, contingent liabilities, asset retirement obligations, the fair value of stock based compensation, and tax provisions. Actual amounts could differ from those estimates.

Accounting for the Effects of Regulation

In accordance with the Accounting Standard Codification (ASC) guidance for regulated operations, our financial statements reflect ratemaking policies prescribed by the regulatory commissions having jurisdiction over our regulated generation and other utility operations (the MPSC, the KCC, the OCC, the APSC and the FERC).

We record a regulatory asset for all or part of an incurred cost that would otherwise be charged to expense in accordance with the ASC guidance for regulated operations which says that an asset should be recorded if it is probable that future revenue in an amount at least equal to the capitalized cost will be allowable for rate making purposes and the current available evidence indicates that future revenue will be provided to permit recovery of the cost. This guidance also indicates that a liability should be recorded when a regulator has provided current recovery for a cost that is expected to be incurred in the future. We follow this guidance for incurred costs or credits that are subject to future recovery from or refund to our customers in accordance with the orders of our regulators.

Historically, all costs of this nature, which are determined by our regulators to have been prudently incurred, have been recoverable through rates in the course of normal ratemaking procedures. Regulatory assets and liabilities are ratably amortized through a charge or credit, respectively, to earnings while being recovered in revenues and fully recognized if and when it is no longer probable that such amounts will be recovered through future revenues. We generally include amortization of regulatory assets and liabilities in the depreciation and amortization line of our statement of cash flows. We continually assess the recoverability of our regulatory assets. Although we believe it unlikely, should retail electric competition legislation be passed in the states we serve, we may determine that we no longer meet the criteria set forth in the ASC guidance for regulated operations with respect to continued recognition of some or all of the regulatory assets and liabilities. Any regulatory changes that would require us to discontinue application of this guidance based upon competitive or other events may also impact the valuation of certain utility plant investments. Impairment of regulatory assets or utility plant investments could have a material adverse effect on our financial condition and results of operations. (See Note 3 for further discussion of regulatory assets and liabilities).

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THE EMPIRE DISTRICT ELECTRIC COMPANY

Notes to Consolidated Financial Statements

Revenue Recognition

For our utility operations, we use cycle billing and accrue estimated, but unbilled, revenue for services provided between the last bill date and the period end date. Unbilled revenues represent the estimate of receivables for energy and natural gas services delivered, but not yet billed to customers. The accuracy of our unbilled revenue estimate is affected by factors including fluctuations in energy demands, weather, line losses and changes in the composition of customer classes.

Municipal Franchise Taxes

Municipal franchise taxes are collected for and remitted to their respective entities and are included in operating revenues and other taxes in the Consolidated Statements of Income. Municipal franchise taxes of $11.1 million, $11.4 million and $11.8 million were recorded for each of the years ended December 31, 2016, 2015 and 2014, respectively.

Accounts Receivable

Accounts receivable are recorded at the tariffed rates for customer usage, including applicable taxes and fees and do not bear interest. We review the outstanding accounts receivable monthly, as well as the bad debt write-offs experienced in the past, and establish an allowance for doubtful accounts. Account balances are charged off against the allowance when management determines it is probable the receivable will not be recovered.

Property, Plant & Equipment

The costs of additions to utility property and replacements for retired property units are capitalized. Costs include labor, material, an allocation of general and administrative costs, and an allowance for funds used during construction (AFUDC). The original cost of regulated units retired or disposed of and the costs of removal are charged to accumulated depreciation, unless the removed property constitutes an operating unit or system. In this case a gain or loss is recognized upon the disposal of the asset. Maintenance expenditures and the removal of minor property items are charged to income as incurred. A liability is created for any additions to electric or gas utility property that are paid for by advances from developers. For a period of five years we refund to the developer a pro rata amount of the original cost of the extension for each new customer added to the extension. Nonrefundable payments at the end of the five year period are applied as a reduction to the cost of the plant in service. The liability as of December 31, 2016 and 2015 was $2.4 million and $2.1 million, respectively.

Depreciation

Provisions for depreciation are computed at straight-line rates in accordance with GAAP consistent with rates approved by regulatory authorities. These rates are applied to the various classes of utility assets on a composite basis. Provisions for depreciation for our other segment are computed at straight-line rates over the estimated useful life of the properties (See Note 2 for additional details regarding depreciation rates).

As of December 31, 2016 and 2015, we had recorded accrued cost of removal of $88.2 million and $85.4 million, respectively, for our electric operating segment. This amount, recorded as a regulatory liability, represents an estimated future cost of dismantling and removing plant from service upon retirement, accrued as part of our depreciation rates. We accrue cost of removal in depreciation rates for mass property (including transmission, distribution and general plant assets). These accruals are not considered an asset retirement obligation under the guidance provided on asset retirement obligations within the ASC. We have a similar cost of removal regulatory liability for our gas operating segment. This amount accrued at December 31, 2016 and 2015 was $10.0 million and $8.8 million, respectively. These amounts are net of our actual cost of removal expenditures.

Asset Retirement Obligation

We record the estimated fair value of legal obligations associated with the retirement of tangible long-lived assets in the period in which the liabilities are incurred and capitalize a corresponding amount as part of the book value of the related long-lived asset. In subsequent periods, we are required to adjust asset retirement obligations based on changes in estimated fair value, and the corresponding increases in asset book values are depreciated over the useful

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THE EMPIRE DISTRICT ELECTRIC COMPANY

Notes to Consolidated Financial Statements

life of the related asset. Uncertainties as to the probability, timing or cash flows associated with an asset retirement obligation affect our estimate of fair value.

We have identified asset retirement obligations associated with the future removal of certain river water intake structures and equipment at the Iatan Power Plant, in which we have a 12% ownership. We also have a solid waste land fill at the Plum Point Energy Station, and asset retirement obligations associated with the removal of asbestos located at the Riverton and Asbury Plants. During 2015 the EPA established a final rule to regulate the disposal of coal combustion residuals (CCRs). As a result of these new rules, an asset retirement obligation of $5.4 million was recorded for the final closure of the existing ash impoundment at our Asbury Power Plant. Separately, an asset retirement obligation of $4.4 million was recorded for our interest in the coal ash impoundment at the Iatan Generating Station. During 2016, the liability for the CCR impoundment at our Asbury Power Plant was re-evaluated and increased by $8.2 million based on updated cost estimates.

In addition, we have a liability for the removal and disposal of Polychlorinated Biphenyls (PCB) contaminants associated with our transformers and substation equipment. These liabilities have been estimated based upon either third party costs or historical review of expenditures for the removal of similar past liabilities. The potential costs of these future expenditures are based on engineering estimates of third party costs to remove the assets in satisfaction of the associated obligations. This liability will be accreted over the period up to the estimated settlement date.

All of our recorded asset retirement obligations have been estimated as of the expected retirement date, or settlement date, and have been discounted using a credit adjusted risk-free rate ranging from 1.93% to 5.52% depending on the settlement date. Revisions to these liabilities could occur due to changes in the cost estimates, anticipated timing of settlement or federal or state regulatory requirements.

The balances at the end of 2016 and 2015, recorded in Other Liabilities, are shown below.

(000’s)	Liability Balance 12/31/15		Liabilities Recognized		Liabilities Settled			Accretion		Cash Flow Revisions		Liability Balance at 12/31/16
Asset Retirement Obligation	$	15,072	$	-	$	(385	)	$	684	$	8,174	$	23,545

(000’s)	Liability Balance 12/31/14		Liabilities Recognized		Liabilities Settled			Accretion		Cash Flow Revisions		Liability Balance at 12/31/15
Asset Retirement Obligation	$	4,847	$	9,812	$	(73	)	$	486	$	-	$	15,072

Upon adoption of the standards on the retirement of long lived assets and conditional asset retirement obligations, we recorded a liability and regulatory asset because we expect to recover these costs of removal in electric and gas rates either through depreciation accruals or direct expenses. We also defer the liability accretion and depreciation expense as a regulatory asset. At December 31, 2016 and 2015, our regulatory assets relating to asset retirement obligations totaled $11.3 million and $7.7 million, respectively.

Allowance for Funds Used During Construction

As provided in the FERC regulatory Uniform System of Accounts, utility plant is recorded at original cost, including an allowance for funds used during construction (AFUDC) when first placed in service. The AFUDC is a utility industry accounting practice whereby the cost of borrowed funds and the cost of equity funds applicable to construction programs are capitalized as a cost of construction. This accounting practice offsets the effect on earnings of the cost of financing current construction, and treats such financing costs in the same manner as construction charges for labor and materials.

AFUDC does not represent current cash income. Recognition of this item as a cost of utility plant is in accordance with regulatory rate practice under which such plant costs are permitted as a component of rate base and the provision for depreciation.

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THE EMPIRE DISTRICT ELECTRIC COMPANY

Notes to Consolidated Financial Statements

In accordance with the methodology prescribed by the FERC, we utilized aggregate rates (on a before-tax basis) of 6.5% for 2016, 5.5% for 2015, and 6.6% for 2014, compounded semiannually.

Asset Impairments (excluding goodwill)

We review long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. To the extent that certain assets may be impaired, analysis is performed based on undiscounted forecasted cash flows to assess the recoverability of the assets and, if necessary, the fair value is determined to measure the impairment amount. None of our assets were impaired as of December 31, 2016 and 2015.

Goodwill

As of December 31, 2016, the consolidated balance sheet included $39.5 million of goodwill. All of this goodwill was derived from our 2006 gas company acquisition and recorded in our gas segment, which is also the reporting unit for goodwill testing purposes. Accounting guidance requires us to test goodwill for impairment on an annual basis or whenever events or circumstances indicate possible impairment.

We applied a qualitative goodwill evaluation model for the annual goodwill impairment test completed in 2016. Based on the results of the qualitative assessment, we believe it was more likely than not that the fair value of the reporting unit exceeded its carrying value as of the testing date, indicating no impairment of our goodwill. The following factors, among others, were considered when assessing whether it was more likely than not that the fair value of the reporting unit exceeded its carrying value for the 2016 test:

● Actual and forecasted financial performance;

● Macroeconomic conditions, Observable industry market

● multiples;

Fuel and Purchased Power

Electric Segment

Fuel and purchased power costs are recorded at the time the fuel is used, or the power purchased. SPP Integrated Marketplace purchased power is also included in fuel and purchased power costs. The net effects of our SPP IM activity, including SPP IM net revenue and net purchased power costs, flow through our fuel recovery mechanisms in each state.

In our Missouri jurisdiction, the MPSC establishes a base cost for the recovery of fuel and purchased power expenses used to supply energy for our fuel adjustment clause (FAC). Beginning with our 2015 rate order, certain transmission costs are also included in the base cost. The FAC permits the distribution to customers of 95% of the changes in fuel and purchased power costs prudently incurred above or below the base cost. Rates related to the fuel adjustment clause are modified twice a year subject to the review and approval by the MPSC. In accordance with the ASC guidance for regulated operations, 95% of the difference between the actual costs of fuel and purchased power and the base cost of fuel and purchased power recovered from our customers is recorded as an adjustment to fuel and purchased power expense with a corresponding regulatory asset or regulatory liability. If the actual fuel and purchased power costs are higher or lower than the base fuel and purchased power costs billed to customers, 95% of these amounts will be recovered from or refunded to our customers when the fuel adjustment clause is modified.

In our Kansas jurisdiction, the costs of fuel are recovered from customers through a fuel adjustment clause, based upon estimated fuel costs and purchased power. The adjustments are subject to audit and final determination by regulators. The difference between the costs of fuel used and the cost of fuel recovered from our Kansas customers is recorded as a regulatory asset or a regulatory liability if the actual costs are higher or lower than the costs billed to customers, in accordance with the ASC guidance for regulated operations.

Similar fuel recovery mechanisms are in place for our Oklahoma, Arkansas and FERC jurisdictions.

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THE EMPIRE DISTRICT ELECTRIC COMPANY

Notes to Consolidated Financial Statements

At December 31, 2016 and 2015, our Missouri, Kansas and Oklahoma fuel and purchased power costs were in a net over-recovered position by $5.8 million and $5.9 million, respectively, which are reflected in our regulatory assets and liabilities.

We receive the renewable attributes associated with the power purchased through our purchased power agreements with Elk River Windfarm LLC and Cloud County Windfarm, LLC. These renewable attributes are converted into renewable energy credits (REC), which are considered inventory, and recorded at zero cost (See Note 11). Revenue from the sale of RECs reduces fuel and purchased power expense.

We have a Stipulation and Agreement with the MPSC granting us authority to manage our emissions allowance inventory in accordance with our Plan for Purchasing and Selling Emissions Allowances (PPSEMA). The PPSEMA allows us to purchase allowances needed for compliance, exchange banked allowances for future vintage allowances and/or monetary value and, in extreme market conditions, to sell allowances outright for monetary value. For compliance years 2016 and 2015 we did not exchange or sell any allowances. We classify our allowances as inventory and they are recorded at cost, with allocated allowances being recorded at zero cost. The allowances are removed from inventory on a FIFO basis, and used allowances are considered to be a part of fuel expense (See Note 11). We had the following emissions allowances in inventory at December 31, 2016 and 2015:

Emission Allowances in Inventory	2016		2015
Acid Rain SO2		22,118		11,443
CSAPR SO2		11,885		5,861
CSAPR NOx (annual)		946		500
CSAPR NOx (seasonal)		259		241

Gas Segment

Fuel expense for our gas segment is recognized when the natural gas is delivered to our customers, based on the current cost recovery allowed in rates. A Purchased Gas Adjustment (PGA) clause allows EDG to recover from our customers, subject to audit and final determination by regulators, the cost of purchased gas supplies and related carrying costs associated with the Company’s use of natural gas financial instruments to hedge the purchase price of natural gas. This PGA clause allows us to make rate changes periodically (up to four times) throughout the year in response to weather conditions and supply demands, rather than in one possibly extreme change per year.

We calculate the PGA factor based on our best estimate of our annual gas costs and volumes purchased for resale. The calculated factor is reviewed by the MPSC staff and approved by the MPSC. Elements considered part of the PGA factor include cost of gas supply, storage costs, hedging contracts, revenue and refunds, prior period adjustments and transportation costs.

Pursuant to the provisions of the PGA clause, the difference between actual costs incurred and costs recovered through the application of the PGA (including costs, cost reductions and carrying costs associated with the use of financial instruments) are reflected as a regulatory asset or liability. The balance is amortized as amounts are reflected in customer billings.

Derivatives

We utilize derivatives to help manage our natural gas commodity market risk resulting from purchasing natural gas, to be used as fuel in our electric business or sold in our natural gas business, or on the spot market. We also acquire Transmission Congestion Rights (TCR) in an attempt to mitigate congestion costs associated with the power we purchase from the SPP Integrated Marketplace (see Note 14).

Electric Segment

Pursuant to the ASC guidance on accounting for derivative instruments and hedging activities, derivatives are required to be recognized on the balance sheet at their fair value. On the date a derivative contract is entered into, the derivative is designated as (1) a hedge of a forecasted transaction or of the variability of cash flows to be received or

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THE EMPIRE DISTRICT ELECTRIC COMPANY

Notes to Consolidated Financial Statements

paid related to a recognized asset or liability (“cash-flow” hedge); or (2) an instrument that is held for non-hedging purposes (a “non-hedging” instrument). We record the mark-to-market gains or losses on derivatives used to hedge our fuel and congestion costs as regulatory assets or liabilities. This is in accordance with the ASC guidance on regulated operations, given that those regulatory assets and liabilities are probable of recovery through our fuel adjustment mechanism.

We also enter into fixed-price forward physical contracts for the purchase of natural gas, coal and purchased power. These contracts, if they meet the definition of a derivative, are not subject to derivative accounting because they are considered to be normal purchase normal sales (NPNS) transactions. If these transactions don’t qualify for NPNS treatment, they would be marked to market for each reporting period through regulatory assets or liabilities.

Gas Segment

Financial hedges for our natural gas business are recorded at fair value on our balance sheet. Because we have a commission approved natural gas cost recovery mechanism (PGA), we record the mark-to-market gain/loss on natural gas financial hedges each reporting period to a regulatory asset/liability account. The regulatory asset/liability account tracks the difference between revenues billed to customers for natural gas costs and actual natural gas expense which is trued up at the end of August each year and included in the Actual Cost Adjustment (ACA) factor to be billed to customers during the next year. This is consistent with the ASC guidance on regulated operations, in that we will be recovering our costs after the annual true up period (subject to a prudency review by the MPSC).

Cash flows from hedges for both electric and gas segments are classified within cash flows from operations.

Pension and Other Postemployment Benefits

We recognize expense related to pension and other postemployment benefits (OPEB) as earned during the employee’s period of service. Related assets and liabilities are established based upon the funded status of the plan compared to the projected benefit obligation. Our pension and OPEB expense or benefit includes amortization of previously unrecognized net gains or losses. Additional income or expense may be recognized when our unrecognized gains or losses as of the most recent measurement date exceed 10% of our postemployment benefit obligation or fair value of plan assets, whichever is greater. For pension benefits and OPEB benefits, unrecognized net gains or losses as of the measurement date are amortized into actuarial expense over ten years.

Pensions

We have rate orders with Missouri, Kansas and Oklahoma that allow us to recover pension costs consistent with our GAAP policy noted above. In accordance with the rate orders, we prospectively calculate the value of plan assets using a market-related value method as allowed by the ASC guidance on pension benefits. As a result, we are allowed to record the Missouri, Kansas and Oklahoma portion of any costs above or below the amount included in rates as a regulatory asset or liability, respectively. The MPSC has allowed us to adopt this pension cost recovery methodology for EDG as well.

Other Postemployment Benefits (OPEB)

We have regulatory treatment for our OPEB costs similar to the treatment described above for pension costs. This includes the use of a market-related value of assets, the amortization of unrecognized gains or losses into actuarial expense over ten years and the recognition of regulatory assets and liabilities as described above.

Additional guidance in the ASC on employers’ accounting for defined benefit pension and other postemployment plans requires an employer to recognize the over funded or underfunded status of a defined benefit postemployment plan (other than a multiemployer plan) as an asset or liability in its statement of financial position and to recognize changes in that funded status in the year in which the changes occur through comprehensive income of a business entity. The guidance also requires an employer to measure the funded status of a plan as of the date of its year-end statement of financial position, with limited exceptions. Pension and other postemployment employee benefits tracking mechanisms are utilized to allow for future rate recovery of these obligations. We record these as regulatory assets on the balance sheet rather than as reductions of equity through comprehensive income (See Note 7).

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THE EMPIRE DISTRICT ELECTRIC COMPANY

Notes to Consolidated Financial Statements

Unamortized Debt Discount, Premium and Expense

Discount, premium and expense associated with long-term debt are amortized over the lives of the related issues. Costs, including gains and losses, related to refunded long-term debt are amortized over the lives of the related new debt issues, in accordance with regulatory rate practices.

Liability Insurance

We are primarily self-insured for workers’ compensation claims, general liabilities, benefits paid under employee healthcare programs and long-term disability benefits. Accruals are primarily based on the estimated undiscounted cost of claims. We self-insure up to certain limits that vary by segment and type of risk. Periodically, we evaluate the level of insurance coverage over the self-insured limits and adjust insurance levels based on risk tolerance and premium expense. We carry excess liability insurance for workers’ compensation and public liability claims for our electric segment. In order to provide for the cost of losses not covered by insurance, an allowance for injuries and damages is maintained based on our loss experience. Our gas segment is covered by the same excess liability insurance for public liability claims, and workers’ compensation claims are covered by a guaranteed cost policy (See Note 11).

Other Noncurrent Liabilities

Other noncurrent liabilities are comprised of accruals and other accounting estimates not sufficiently large enough to merit individual disclosure. At December 31, 2016, the balance of other noncurrent liabilities is primarily comprised of accruals for self-insurance, customer advances for construction and asset retirement obligations.

Cash & Cash Equivalents

Cash and cash equivalents include cash on hand and temporary investments purchased with an initial maturity of three months or less. It also includes checks and electronic funds transfers that have been issued but have not cleared the bank, which are also reflected in current accrued liabilities and were $9.2 million and $23.2 million at December 31, 2016 and 2015, respectively.

Restricted Cash

As part of our Plum Point ownership agreement, we are required to have funds available in an escrow account which guarantees payment of certain operating costs. The cash is held at a financial institution and restricted as to withdrawal or use. The amounts restricted, which were $1.8 million at December 31, 2016 and 2015, may increase or decrease based on an annual review.

We are required to post cash collateral with Southwest Power Pool (SPP) to participate in Transmission Congestion Rights (TCR) auctions. The cash is held at a financial institution and restricted as to withdrawal or use. The amounts of such restricted cash were $2.5 million at December 31, 2016 and 2015.

Due to our Plum Point energy station interconnection with Midcontinent Independent System Operator (MISO), we participate in Financial Transmission Rights (FTR) auctions which require us to post cash collateral. The cash is held at a financial institution and restricted as to withdrawal or use. The amounts of such restricted cash were $0.5 million at December 31, 2016 and 2015.

Fuel, Materials and Supplies

Fuel, materials and supplies consist primarily of coal, natural gas in storage and materials and supplies, which are reported at average cost. These balances are as follows (in thousands):

	2016		2015
Electric fuel inventory	$	22,944	$	30,185
Natural gas inventory		2,513		3,868
Materials and supplies		30,590		26,897
TOTAL	$	56,047	$	60,950

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THE EMPIRE DISTRICT ELECTRIC COMPANY

Notes to Consolidated Financial Statements

Income Taxes

Deferred tax assets and liabilities are recognized for the tax consequences of transactions that have been treated differently for financial reporting and tax return purposes. The temporary differences are measured using statutory tax rates (See Note 9).

Investment tax credits utilized in prior years were deferred as a noncurrent liability and are being amortized over the useful lives of the properties to which they relate. The longest remaining amortization period for investment tax credits is approximately 54 years. Deferred income taxes were recorded on the temporary difference represented by the deferred investment tax credits and a corresponding regulatory liability. This recognizes the expected reduction in rates for future lower income taxes associated with the amortization of the investment tax credits.

Accounting for Uncertainty in Income Taxes

The FASB has issued guidance on accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with the ASC guidance on accounting for income taxes. With few exceptions, we are no longer subject to U.S. federal, state and local income tax examinations by tax authorities for years before 2011. At December 31, 2016 and 2015, our balance sheet did not include provisions for any uncertain tax positions. We do not expect any material changes to this tax position within the next twelve months. Our policy is to recognize interest and penalties, if any, related to unrecognized tax benefits in other expenses.

Computations of Earnings Per Share

The ASC guidance on earnings per share requires dual presentation of basic and diluted earnings per share. Basic earnings per share does not include potentially dilutive securities and is computed by dividing net income by the weighted average number of common shares outstanding. Diluted earnings per share assumes the issuance of common shares pursuant to the Company’s stock-based compensation plans at the beginning of each respective period, or at the date of grant or award if later.

Weighted Average Number Of Shares	2016		2015		2014
Basic		43,999,783		43,670,908		43,291,031
Dilutive Securities:
Performance-based restricted stock awards		40,278		19,890		8,809
Employee stock purchase plan		-		1,249		3,422
Time-based restricted stock awards		26,297		25,523		10,666
Total dilutive securities		66,575		46,662		22,897
Diluted weighted average number of shares		44,066,358		43,717,570		43,313,928
Antidilutive Shares		25,495		20,289		25,259

Stock-Based Compensation

Prior to the closing of the Merger, we maintained several stock-based compensation plans, which are described in more detail in Note 8. In accordance with the ASC guidance on stock-based compensation, we recognized compensation expense over the requisite service period of all stock-based compensation awards based upon the fair-value of the award as of the date of issuance.

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 was 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 $8.0 million in unamortized

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THE EMPIRE DISTRICT ELECTRIC COMPANY

Notes to Consolidated Financial Statements

debt issuance costs being reclassified from deferred charges to long-term debt on the December 31, 2016 Consolidated Balance Sheet.

Revenue from contracts with customers: In June 2014, the FASB issued new guidance governing revenuerecognition. 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 expect that the adoption of the guidance will result in a one-time increase in revenue related to the change in the timing of revenue recognition under the new guidance. There are some portions of the standard which we are still evaluating; however we do not expect the application of these portions of the guidance to have a material impact on our results of operations, financial position or liquidity.

Leases: In February 2016, the FASB issued new guidance on accounting for leases. Under the new guidance alessee 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 updatedguidance 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 revisedguidance 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 guidanceaddressing 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.

Statement of cash flows presentation of changes in restricted cash: In November 2016, the FASB issued revisedguidance addressing the presentation of changes in restricted cash on the statement of cash flows intended to address diversity in practice. Under the revised guidance amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. 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.

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THE EMPIRE DISTRICT ELECTRIC COMPANY

Notes to Consolidated Financial Statements

2. PROPERTY, PLANT AND EQUIPMENT

Our total property, plant and equipment are summarized below (in thousands).

	December 31,
	2016		2015
Electric plant
Production	$	1,343,565	$	1,151,395
Transmission		338,352		316,038
Distribution		903,714		870,047
General(1)		127,383		123,338
Electric plant		2,713,014		2,460,818
Less accumulated depreciation and amortization(2)		776,276		721,883
Electric plant net of depreciation and amortization		1,936,738		1,738,935
Construction work in progress(3)		28,485		182,585
Net electric plant		1,965,223		1,921,520
Water plant		13,250		13,109
Less accumulated depreciation and amortization		5,541		5,281
Water plant net of depreciation and amortization		7,709		7,828
Construction work in progress		340		75
Net water plant		8,049		7,903
Net electric segment plant		1,973,272		1,929,423
Gas plant
Transmission		8,480		8,498
Distribution		69,996		66,588
General (4)		8,595		8,316
Gas Plant		87,071		83,402
Less accumulated depreciation and amortization		20,565		18,557
Gas plant net of accumulated depreciation		66,506		64,845
Construction work in progress		0		627
Net gas plant		66,506		65,472
Other
Fiber		45,181		44,263
Less accumulated depreciation and amortization		20,905		19,174
Non-regulated net of depreciation and amortization		24,276		25,089
Construction work in progress		197		402
Net non-regulated property		24,473		25,491
TOTAL NET PLANT AND PROPERTY	$	2,064,251	$	2,020,386

(1) Includes intangible property of $40.7 million and $39.8 million as of December 31, 2016 and 2015, respectively, primarily related to capitalized software and investments in facility upgrades owned by other utilities. Accumulated amortization related to this property in 2016 and 2015 was $16.9 and $15.6 million, respectively.

(2) As part of our depreciation rates, we accrue the estimated cost of dismantling and removing plant from service upon retirement. See the depreciation discussion under Note 1 and Note 3 Regulatory Matters for more detail.

(3) Construction work in progress decreased at December 31, 2016 as compared to 2015 reflecting the completion of the Riverton 12 combined cycle project.

(4) Includes intangible property of $0.9 million as of both December 31, 2016 and 2015, primarily related to capitalized software and investments in facility upgrades owned by other utilities. Accumulated amortization related to this property in 2016 and 2015 was $0.7 million and $0.6 million, respectively.

The table below summarizes the total provision for depreciation and the depreciation rates for continuing operations, both capitalized and expensed, for the years ended December 31 (in thousands):

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THE EMPIRE DISTRICT ELECTRIC COMPANY

Notes to Consolidated Financial Statements

	2016		2015		2014
Provision for depreciation
Regulated – Electric and Water(1)	$	79,106	$	73,885	$	66,600
Regulated – Gas(1)		4,142		4,036		3,851
Non-Regulated		1,951		1,895		1,891
TOTAL		85,199		79,816		72,342
Amortization		3,122		2,858		2,692
TOTAL	$	88,321	$	82,674	$	75,034

(1) A portion of this amount is reclassified to a regulatory liability for the estimated future cost of removal. See the depreciation discussion under Note 1 and Note 3 Regulatory Matters for more detail.

	2016			2015			2014
Annual depreciation rates
Electric and water		3.1	%		3.1	%		3.0	%
Gas		5.0	%		5.1	%		5.2	%
Non-Regulated		4.4	%		4.4	%		4.7	%
TOTAL COMPANY		3.2	%		3.2	%		3.0	%

The table below sets forth the average depreciation rate for each class of assets for each period presented:

Annual Weighted Average Depreciation Rate	2016			2015			2014
Electric fixed assets:
Production plant		2.9	%		2.8	%		2.4	%
Transmission plant		2.4	%		2.4	%		2.4	%
Distribution plant		3.4	%		3.5	%		3.6	%
General plant		5.8	%		5.9	%		5.8	%
Water		2.7	%		2.8	%		2.7	%
Gas		5.0	%		5.1	%		5.2	%
Non-regulated		4.4	%		4.4	%		4.7	%

3. REGULATORY MATTERS

Regulatory Assets and Liabilities and Other Deferred Credits

Changes

Changes to regulatory assets and liabilities regarding their rate base inclusion or amortizable lives from December 31, 2015 to December 31, 2016 resulted from our 2015 Missouri rate case, which was effective September 14, 2016. A tracking mechanism for non-labor operating and maintenance expenses, established in our 2014 Missouri rate case, for the Riverton 12 Combined Cycle Unit will continue. The balances accumulated in the discontinued tracking mechanisms from the 2014 Missouri rate case for Iatan 2, Iatan Common and Plum Point will be amortized over three years, and the vegetation management tracker balance will be amortized over five years. In addition to these changes, the order also included the continuation of tracking mechanisms for pension and other post-employment benefit expenses.

Changes to regulatory assets and liabilities regarding their rate base inclusion or amortizable lives from December 31, 2014 to December 31, 2015 resulted from our 2014 Missouri rate case, which was effective July 26, 2015. As a result of this case, a new tracking mechanism related to our Riverton Unit 12 Long Term Maintenance Agreement was established. The tracking mechanisms related to Iatan 2, Iatan Common and Plum Point operating and maintenance costs were discontinued. The balances accumulated through August 2014 from these tracking mechanisms are to be amortized over three years. The tracking mechanism related to vegetation management was also discontinued. Balances accumulated through August 2014 will be amortized over five years. The balances accumulated in these discontinued tracking mechanisms after August 2014 were addressed during the 2016 rate case, as described above. In addition to these changes, the order also included the continuation of tracking mechanisms for expenses related to employee pension and retiree health care.

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THE EMPIRE DISTRICT ELECTRIC COMPANY

Notes to Consolidated Financial Statements

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

	December 31,
Regulatory Assets:	2016			2015
Current:
Under recovered fuel costs	$	847		$	196
Current portion of long-term regulatory assets		7,543			6,856
Regulatory assets, current		8,390			7,052
Long-term:
Pension and other postemployment benefits		103,186			108,273
Income taxes		48,925			48,613
Deferred construction accounting costs(1)		14,625			14,977
Unamortized loss on reacquired debt		9,058			9,731
Under recovered fuel costs		3,514			-
Unsettled derivative losses – electric segment		2,155			7,775
System reliability – vegetation management		2,055			3,604
Storm costs(2)		2,983			3,531
Deferred operating and maintenance expense		1,897			-
Asset retirement obligation		11,349			7,722
Customer programs		6,566			5,942
Missouri solar initiative(3)		11,160			3,504
Current portion of long-term regulatory assets		(7,543	)		(6,856	)
Other		2,155			2,892
Regulatory assets, long-term		212,085			209,708
Total Regulatory Assets	$	220,475		$	216,760
Regulatory Liabilities
Current:
Over recovered fuel costs	$	11,360		$	5,280
Current portion of long-term regulatory liabilities		3,146			3,335
Regulatory liabilities, current		14,506			8,615
Long-term:
Costs of removal(4)		98,225			94,193
SWPA payment for Ozark Beach lost generation		11,674			14,213
Income taxes		11,040			11,244
Deferred construction accounting costs – fuel(5)		7,535			7,690
Unamortized gain on interest rate derivative		2,861			3,031
Pension and other postemployment benefits		2,018			1,745
Over recovered fuel costs		5,817			2,300
System reliability – vegetation management		-			1,320
Current portion of long-term regulatory liabilities		(3,146	)		(3,335	)
Other		-			56
Regulatory liabilities, long-term		136,024			132,457
Total Regulatory Liabilities	$	150,530		$	141,072

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

(2) Reflects ice storm costs incurred in 2007 and costs incurred as a result of the May 2011 tornado including an accrued carrying charge and deferred depreciation totaling $2.5 million at December 31, 2016.

(3) Resulting from the Missouri Clean Energy Initiative and consists of approximately 912 solar rebate applications processed as of December 31, 2016, (compared to 262 as of December 31, 2015), resulting in solar rebate-related costs totaling approximately $11.2 million.

(4) As part of our depreciation rates, we accrue the estimated cost of dismantling and removing plant from service upon retirement and these costs are reflected here. See the depreciation discussion under Note 1 and Note 2 for more detail.

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

Unamortized losses on debt and losses on interest rate derivatives are not included in rate base, but are included in our capital structure for rate base purposes. The remainder of our regulatory assets are not included in rate base, generally because they are not cash items. However, as of December 31, 2016, the costs of all of our regulatory assets are currently being recovered except for approximately $99.0 million of pension and other postemployment costs primarily related to the unfunded liabilities for future pension and OPEB costs. We expect recovery of the

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THE EMPIRE DISTRICT ELECTRIC COMPANY

Notes to Consolidated Financial Statements

unfunded amount but the timing of the recovery will be based on the changing funded status of the pension and OPEB plans in future periods.

The regulatory income tax assets and liabilities are generally amortized over the average depreciable life of the related assets. The loss on reacquired debt and the loss and gain on interest rate derivatives are amortized over the life of the related new debt issue, which currently ranges from 4 to 24 years. The unrecovered fuel costs are generally recovered within a year following their recognition. Pension and OPEB tracking mechanisms are recovered over a five year period. The cost of removal regulatory liability is amortized as removal costs are incurred.

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 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, 2014:

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

Electric Segment

Missouri

Rate Activity

2015 Rate Case: 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%. 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.

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THE EMPIRE DISTRICT ELECTRIC COMPANY

Notes to Consolidated Financial Statements

2014 Rate Case: On August 29, 2014, we filed a request with the MPSC for changes in rates for our Missouri electric customers. We requested an annual increase in total revenue of approximately $24.3 million, or approximately 5.5%. The main cost drivers in the rate increase were the costs associated with our investment in Air Quality Control Facilities at our Asbury power plant that were incurred to comply with the Environmental Protection Agency’s (EPA) rules governing the continued operation of the plant, increases in property taxes, increases in ongoing maintenance expenses and increases in Regional Transmission Organization transmission fees. On June 24, 2015, the MPSC granted new rates for Missouri customers, effective on July 26, 2015. The order approved an annual increase in base revenues of about $17.1 million or 3.90%, which included a net reduction in base fuel and purchased power of $1.60 per MWh, consistent with the non-unanimous stipulation and agreement filed April 8, 2015. The order established a tracking mechanism for expenses related to the Riverton 12 long-term maintenance contract; continued tracking of pension and other post-employment benefit expenses; and discontinued tracking of vegetation management expenses and Iatan 2, Iatan Common and Plum Point operating and maintenance costs. In addition, the order provided for the tracking and recovery of certain future changes in total transmission expense through the Fuel Adjustment Charge, which we estimate at approximately 34% of such changes.

2015 Solar Rebate Tariff

On May 5, 2015, we filed a proposed solar rebate tariff with the MPSC and requested expedited treatment. On May 6, 2015, the MPSC ordered our request for expedited treatment of our tariff filing be granted and approved the tariff, effective May 16, 2015. 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.

Integrated Resource Plan and Missouri Energy Efficiency Investment Act

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 11.

On August 24, 2016, an Amended Stipulation and Agreement as to Division of Energy and Renew Missouri was filed in the Merger case in which we agreed to make a Missouri Energy Efficiency Investment Act (MEEIA) filing, provided a statewide Technical Reference Manual (TRM) has been approved by the state, and provided our next Triennial IRP (2019 or 2022, depending on the date a TRM is approved) favors a plan with increased demand-side management (DSM) investments. We will work with the Missouri Division of Energy (DE), the MPSC Staff, the Office of the Public Counsel (OPC) and other parties through the existing DSM Advisory Group to review and consider the viability of adopting additional energy efficiency programs for our customers. Within one year of the MPSC’s finding of substantial compliance of the Empire IRP that follows MPSC approval of a TRM, we will develop and submit an application for approval of a portfolio of DSM programs under MEEIA, so long as any such portfolio is a part of our adopted preferred resource plan in our IRP, or has been analyzed through the integration process required and the portfolio and any DSM submitted in the application is fully compliant with the MEEIA statute and applicable regulations.

Kansas

2016 Rate Case: 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 the filing with the KCC of a Unanimous Settlement Agreement with respect to the joint application for approval of the Merger filed March 16, 2016, 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 was to be withdrawn and current base rates are to remain in effect through January 1, 2019. The agreement also provided that we could 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.

The KCC approved the Unanimous Settlement Agreement on December 22, 2016.

On January 11, 2017, we filed a request to implement a rider, the Asbury Environmental and Riverton Rider (AERR), in place of the Asbury Environmental Rider (AER) currently in effect in our Kansas jurisdiction. The new rider will provide a mechanism to begin recovering costs related to the $168 million combined cycle generating unit at the Riverton

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Notes to Consolidated Financial Statements

Power Plant. If approved, the rider would result in an increase in annual revenues of $1.87 million. The KCC will conduct a review of the filing prior to implementation of the new rider. The new rider is expected to take effect no later than 210 days from the date of filing.

Concurrently with filing the AERR, we withdrew the general rate case filed with the KCC on September 16, 2016, in accordance with the Unanimous Settlement Agreement.

2015 Ad Valorem Tax Surcharge

On January 22, 2015, we filed an Application with the KCC requesting approval of our Ad Valorem Tax Surcharge (AVTS). The request sought approval for an annual increase of $0.27 million related to increases in Ad Valorem taxes which exceed amounts currently included in base rates. On February 19, 2015, the KCC approved the request. The new rate was effective February 23, 2015. On January 21, 2016, we filed an Application with the KCC requesting approval for a revision to the AVTS. The request sought approval for an annual increase of an additional $0.2 million related to increases in Ad Valorem taxes which exceed amounts currently included in our AVTS rider. This is an annual filing.

2014 Environmental Cost Recovery Rider

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

Oklahoma

On June 8, 2015, the governor of the state of Oklahoma approved an administrative ruling that provides customer rate reciprocity to electric companies who serve less than 10% of total customers within the state of Oklahoma. As a result, future increases in Missouri customer rates approved by the MPSC could be effective for our Oklahoma customers, subject to Oklahoma Corporation Commission (OCC) approval. On October 26, 2015, we filed a request with the OCC to adopt the Missouri customer electric rates requested in our October 16, 2015 Missouri rate filing, discussed above, for our Oklahoma customers once approval is granted by the MPSC.

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 December 21, 2016, we filed a request with the OCC for changes in rates for our Oklahoma electric customers, seeking an increase in annual revenues of approximately $3.8 million, or approximately 27.58%. Primary drivers for this case include the $112 million Air Quality Control System (AQCS) at the Asbury Power Plant, the $168 million combined cycle generating unit at the Riverton Power Plant; upgrades to financial, asset, and work management software systems; and other reliability and system improvements to serve customers.

Arkansas

2016 Cost Recovery Rider

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 began collecting approximately $0.6 million of additional annual revenue on November 1, 2016.

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THE EMPIRE DISTRICT ELECTRIC COMPANY

Notes to Consolidated Financial Statements

2015 Tariff Rider

On February 23, 2015, we filed a notice with the Arkansas Public Service Commission (APSC) to implement the Alternative Generation Environmental Recovery Rider (GER) pursuant to the provision of Act 310 of 1981. The GER recovers reasonably incurred costs and expenditures as a direct result of legislative or regulatory requirements relating to the protection of the public health, safety, or the environment. Our implemented GER recovers our Arkansas jurisdictional share of investment associated with the Asbury AQCS. The new GER was effective upon notice (February 23, 2015) subject to refund. On August 5, 2015, the APSC approved the GER.

2014 Rate Case

On May 20, 2014, we filed a settlement agreement with the Arkansas Public Service Commission (APSC) for an increase of $1.375 million, or approximately 11%. A hearing was held on the settlement agreement on July 22, 2014. On September 16, 2014, the APSC issued an order approving the settlement with a modification that reduced the overall revenue increase to $1.367 million. The new rates were effective September 26, 2014. We had filed a request on December 3, 2013, with the APSC seeking an annual increase in total revenue of approximately $2.2 million, or approximately 18%. The rate increase was requested to recover costs incurred to ensure continued reliable service for our customers, including capital investments, operating systems replacement costs and ongoing increases in other operation and maintenance expenses and capital costs.

FERC

We have in place a cost-based transmission formula rate (TFR). On June 13, 2013, we, the Kansas Corporation Commission and the cities of Monett, Mt. Vernon and Lockwood, Missouri and Chetopa, Kansas, filed a unanimous Settlement Agreement (Agreement) with the FERC. The Agreement included a TFR that would establish an ROE of 10.0%. The Agreement calls for the TFR to be updated annually with the new updated TFR rates effective on July 1 of each year. FERC conditionally approved the Agreement on November 18, 2013, and we made a compliance filing with FERC on December 18, 2013 in connection with this conditional approval. The FERC approved our compliance filing on June 12, 2014.

We have in place a cost-based generation formula rate (GFR). Our GFR requires an update to be completed annually for rates effective June 1. On October 29, 2014, Empire made a “limited” Section 205 filing to request some minor changes in the existing GFR formula to incorporate the impact of the recent implementation of the Southwest Power Pool Integrated Marketplace (IM). As a result of this filing, our customers’ share of the margins we receive from sales into the IM will be passed on to them through the monthly fuel and purchased power cost adjustment mechanism rather than making one-time adjustments at each annual update. This filing was approved by FERC on January 13, 2015.

MARKETS AND TRANSMISSION

Electric Segment

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

As part of the IM, we and other SPP members submit generation offers to sell our power and bids to purchase power into the SPP market, with the SPP serving as a centralized commitment and dispatch of SPP members’ generation resources. The SPP matches offers and bids based upon operating and reliability considerations. The SPP reports that approximately 90%-95% of all next day generation needed throughout the SPP territory is being cleared through the IM. 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. 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. These rights are recorded as reductions to purchased power costs.

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Notes to Consolidated Financial Statements

FERC Order No. 1000: In July 2011, the FERC issued Order No. 1000 (Transmission Planning and Cost Allocation by Transmission Owning and Operating Public Utilities) which requires all public utility transmission providers to allow transmission developers outside their retail distribution service territory to participate in regional transmission planning. Order No. 1000 eliminates the federal right of first refusal for entities that develop transmission projects within their own retail distribution service territories to construct transmission facilities selected in a regional transmission plan. This order will directly affect our rights to build 161kV and above transmission facilities within our retail service territory.

Order No. 1000 also directed transmission providers to develop policy and procedures for regional and interregional transmission planning as well as regional and interregional transmission cost allocation for approved transmission projects. We continue to participate in the SPP processes to understand the impact of these FERC orders on our ability to construct new facilities within our service territory as well as their influence on promoting construction of transmission projects on or near our borders with our neighbors. SPP completed and filed with the FERC a required interregional policy and procedure compliance filing, and while FERC partially approved SPP’s compliance filing, remaining issues have been addressed in a subsequent filing that is currently waiting FERC approval.

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

As a result, we have participated with the SPP members and other impacted utilities in two separate FERC settlement proceedings in an effort to reduce the costs to our customers. On October 13, 2015, SPP members, SPP, MISO and MISO members filed a settlement at the FERC regarding MISO’s unreserved and uncompensated use of the SPP members’ systems. As approved by the FERC, the agreement provides compensation and governance for the continued shared use of the transmission system among MISO, SPP and other impacted utilities. The regional through and out transmission delivery rate (RTOR) dispute regarding Plum Point proceeded through settlement discussions and a resulting settlement agreement was filed with the FERC on February 25, 2016. The settlement closed on June 23, 2016 and we withdrew all claims on July 6, 2016. We have received a total of $2.1 million in MISO Through-and Out refunds in 2016.

Gas Segment

Non-residential gas customers whose annual usage exceeds certain amounts may purchase natural gas from a source other than EDG. EDG does not have a non-regulated energy marketing service that sells natural gas in competition with outside sources. EDG continues to receive non-gas related revenues for distribution and other services if natural gas is purchased from another source by our eligible customers.

Other - Rate Matters

In accordance with ASC guidance on regulated operations, we currently have deferred approximately $0.4 million of expense related to rate cases under other non-current assets and deferred charges. These amounts will be amortized over varying periods based upon the completion of the specific cases. Based on past history, we expect all these expenses to be recovered in rates.

4. SHAREHOLDERS’ EQUITY

Shelf Registration

Prior to the closing of the Merger, we maintained a $200.0 million shelf registration statement with the SEC covering our common stock, unsecured debt securities, preference stock, and first mortgage bonds which expired in December 2016. However, as a result of the Merger, the shelf registration was not renewed.

Employee Benefit Plans

Prior to the closing of the Merger, our Employee Stock Purchase Plan (“ESPP”) permitted the granting to eligible employees of options to purchase our common stock at a discounted price. As of December 31, 2016 there were

24

THE EMPIRE DISTRICT ELECTRIC COMPANY

Notes to Consolidated Financial Statements

707,737 shares available for issuance in this plan. Under our Employee 401(k) Plan and ESOP we matched a percentage of each employee’s deferrals by contributing shares of our common stock. At December 31, 2016 there were 78,453 shares available to be issued. (See Note 7 for further discussion of these plans).

Equity Based Compensation

Prior to the closing of the Merger, we maintained several stock-based awards programs, which are described in Note 8. Our 2015 Stock Incentive Plan provided for grants of up to 500,000 shares of common stock through January 2025. At December 31, 2016 there were 459,093 shares available to be issued.

Dividends

Holders of our common stock are entitled to dividends if, as and when declared by the Board of Directors, out of funds legally available therefore, subject to the prior rights of holders of any outstanding cumulative preferred stock and preference stock. Payment of dividends is determined by our Board of Directors after considering all relevant factors, including the amount of our retained earnings (which is essentially our accumulated net income less dividend payouts).

The following table shows our diluted earnings per share, dividends paid per share, total dividends paid and retained earnings balance for the years ended December 31, 2016, 2015 and 2014.

(in millions, except per share amounts)	2016		2015		2014
Diluted earnings per share	$	1.45	$	1.29	$	1.55
Dividends paid per share	$	1.129	$	1.04	$	1.025
Total dividends paid	$	45.8	$	45.4	$	44.4
Retained earnings year-end balance	$	115.8	$	101.4	$	90.3

On December 22, 2016, our Board of Directors declared a special prorated dividend in the amount of $0.002857 per share, per day on the Company’s outstanding common stock that accrued from December 1, 2016 until December 31, 2017, the day immediately preceding the Merger Closing Date. The special prorated dividend was equal to the daily equivalent of the then-current quarterly dividend rate of $0.26 per share, payable to shareholders of record on December 30, 2016. The special prorated dividend totaling approximately $3.9 million was accrued at December 31, 2016 and was paid on January 17, 2017.

The EDE Mortgage and our Restated Articles contain certain dividend restrictions. The most restrictive of these is contained in the EDE Mortgage, which provides that we may not declare or pay any dividends (other than dividends payable in shares of our common stock) or make any other distribution on, or purchase (other than with the proceeds of additional common stock financing) any shares of, our common stock if the cumulative aggregate amount thereof after August 31, 1944 (exclusive of the first quarterly dividend of $98,000 paid after said date) would exceed the sum of $10.75 million and the earned surplus (as defined in the EDE Mortgage) accumulated subsequent to August 31, 1944, or the date of succession in the event that another corporation succeeds to our rights and liabilities by a merger or consolidation. The EDE Mortgage permits the payment of any dividend or distribution on, or purchase of, shares of our common stock within 60 days after the related date of declaration or notice of such dividend, distribution or purchase if (i) on the date of declaration or notice, such dividend, distribution or purchase would have complied with the provisions of the EDE Mortgage and (ii) as of the last day of the calendar month ended immediately preceding the date of such payment, our ratio of total indebtedness to total capitalization (after giving pro forma effect to the payment of such dividend, distribution, or purchase) was not more than 0.625 to 1.

Preferred and Preference Stock

Prior to the closing of the Merger, we had 2.5 million shares of preference stock authorized, including 0.5 million shares of Series A Participating Preference Stock, none of which have been issued. We had 5 million shares of $10.00 par value cumulative preferred stock authorized. There was no preferred stock issued and outstanding at December 31, 2016 or 2015.

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THE EMPIRE DISTRICT ELECTRIC COMPANY

Notes to Consolidated Financial Statements

5. LONG-TERM DEBT

At December 31, 2016 and 2015, the balance of long-term debt outstanding was as follows (in thousands):

	2016			2015
First mortgage bonds (EDE):
7.20%Series due 2016	$	-		$	25,000
6.375% Series due 2018 (1)		90,000			90,000
4.65%Series due 2020 (1)		100,000			100,000
3.58%Series due 2027 (1)		88,000			88,000
3.59%Series due 2030 (1)		60,000			60,000
3.73%Series due 2033 (1)		30,000			30,000
5.875% Series due 2037 (1)		80,000			80,000
5.20%Series due 2040 (1)		50,000			50,000
4.32%Series due 2043 (1)		120,000			120,000
4.27%Series due 2044 (1)		60,000			60,000
First mortgage bonds (EDG):
6.82%Series due 2036 (1)		55,000			55,000
		733,000			758,000
Senior Notes, 6.70% Series due 2033 (1)		62,000			62,000
Senior Notes, 5.80% Series due 2035 (1)		40,000			40,000
Capital lease obligations		3,579			3,890
Less unamortized debt expense		(7,954	)		(8,658	)
Less unamortized net discount		(581	)		(633	)
		830,044			854,599
Current unamortized debt expense		-			64
Less current obligations of long-term debt		-			(25,000	)
Less current obligations under capital lease		(329	)		(310	)
TOTAL LONG-TERM DEBT	$	829,715		$	829,353

⁽¹⁾ We may redeem some or all of the notes at any time at 100% of their principal amount, plus a make-whole premium, plus accrued and unpaid interest to the redemption date.

Debt Financing Activities

On June 11, 2015, we entered into a Bond Purchase Agreement for a private placement of $60.0 million of 3.59% First Mortgage Bonds due 2030. A delayed settlement occurred on August 20, 2015. Interest is payable semi-annually on the bonds on each February 20 and August 20, commencing February 20, 2016. The bonds are prepayable at our option at any time prior to maturity, at par plus a make whole premium, together with accrued and unpaid interest, if any, to the prepayment date. The proceeds from the sale of the bonds were used to refinance existing short-term indebtedness and for general corporate purposes. The bonds have not been and will not be registered under the Securities Act of 1933, as amended. The bonds were issued under the EDE Mortgage.

On October 15, 2014, we entered into a Bond Purchase Agreement for a private placement of $60.0 million of 4.27% First Mortgage Bonds due December 1, 2044. A delayed settlement occurred on December 1, 2014. Interest is payable semi-annually on the bonds on each December 1 and June 1, commencing June 1, 2015. The bonds may be redeemed at our option, at any time prior to maturity, at par plus a make whole premium, together with accrued and unpaid interest, if any, to the redemption date. The proceeds from the sale of the bonds were used to refinance existing short-term indebtedness and for general corporate purposes. The bonds have not been, and will not be, registered under the Securities Act of 1933, as amended. The bonds were issued under the EDE Mortgage.

Shelf Registration

We had a $200.0 million shelf registration statement with the SEC which expired in December 2016. See Note 4.

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.

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THE EMPIRE DISTRICT ELECTRIC COMPANY

Notes to Consolidated Financial Statements

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 $322.0 million of new first mortgage bonds. The EDE Mortgage contains a requirement that for new first mortgage bonds to be issued, our net earnings (as defined in the EDE Mortgage) for any twelve consecutive months within the fifteen months preceding issuance must be two times the annual interest requirements (as defined in the EDE Mortgage) on all first mortgage bonds then outstanding and on the prospective issue of new first mortgage bonds. In addition to the interest coverage requirement, the EDE Mortgage provides that new bonds must be issued against, among other things, retired bonds or 60% of net property additions. The annual interest coverage requirement and retired bonds or 60% of net property additions test would permit the issuance of more than $322.0 million of first mortgage bonds; however, as discussed above, we are otherwise limited to the issuance of no more than $322.0 million of new first mortgage bonds. As of December 31, 2016, we are in compliance with all restrictive covenants of the EDE Mortgage.

EDG Mortgage Indenture

The principal amount of all series of first mortgage bonds outstanding at any one time under the Indenture of Mortgage and Deed of Trust of The Empire District Gas Company (EDG Mortgage) is limited by terms of the mortgage to $300.0 million. Substantially all of the property, plant and equipment of The Empire District Gas Company is subject to the lien of the EDG Mortgage. The EDG Mortgage contains a requirement that for new first mortgage bonds to be issued, the amount of such new first mortgage bonds shall not exceed 75% of the cost of property additions acquired after the date of the Missouri Gas acquisition. The mortgage also contains a limitation on the issuance by EDG of debt (including first mortgage bonds, but excluding short-term debt incurred in the ordinary course under working capital facilities) unless, after giving effect to such issuance, EDG’s ratio of EBITDA (defined as net income plus interest, taxes, depreciation, amortization and certain other non-cash charges) to interest charges for the most recent four fiscal quarters is at least 2.0 to 1.0. As of December 31, 2015, this test would allow us to issue approximately $16.3 million principal amount of new first mortgage bonds at an assumed interest rate of 5.5%. As of December 31, 2016, we are in compliance with all restrictive covenants of the EDG Mortgage.

Our long-term debt obligations over the next five years are as follows (in thousands):

	Payments Due By Period
Long-Term Debt Payout Schedule (Excluding Unamortized Discount) (in thousands)	Total		Regulated Entity Debt Obligations		Capital Lease Obligations
2017	$	329	$	0	$	329
2018		90,351		90,000		351
2019		374		-		374
2020		100,395		100,000		395
2021		422		-		422
Thereafter		646,708		645,000		1,708
Total long-term debt obligations		838,579	$	835,000	$	3,579
Less current obligations and unamortized discount		8,864
TOTAL LONG-TERM DEBT	$	829,715

6. SHORT-TERM BORROWINGS

At December 31, 2016, total short-term borrowings consisted of $24.8 million in commercial paper and no borrowings under our line of credit. During 2016 and 2015 our short-term borrowings outstanding averaged (in millions):

	2016		2015
Average borrowings outstanding	$	14.3	$	48.9
Highest month end balance	$	36.0	$	97.0

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THE EMPIRE DISTRICT ELECTRIC COMPANY

Notes to Consolidated Financial Statements

The weighted average interest rates and the weighted average interest rate of borrowings outstanding at December 31, 2016 and 2015 were:

	2016			2015
Weighted average interest rate		0.84	%		0.54	%
Weighted average interest rate of borrowings outstanding		1.02	%		0.84	%

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.

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

The credit facility requires our total indebtedness to be less than 65.0% of our total capitalization at the end of each fiscal quarter and a failure to maintain this ratio will result in an event of default under the credit facility and will prohibit us from borrowing funds thereunder. As of December 31, 2016, we were in compliance with this covenant as our total indebtedness to total capitalization was 50.7%. The 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 December 31, 2016, we were not in default under any of our debt obligations.

The credit agreement does not legally restrict the use of our cash in the normal course of operations. There were no outstanding borrowings under the agreement at December 31, 2016; however, $24.8 million was used to back up our outstanding commercial paper.

7. RETIREMENT AND OTHER EMPLOYEE BENEFITS

We record retirement benefits in accordance with the ASC guidance on accounting for pension and other postemployment benefits, and have recorded the appropriate liabilities to reflect the unfunded status of our benefit plans, with offsetting entries to a regulatory asset, because we believe it is probable the unfunded amount of these plans will be afforded rate recovery. Additionally, the MPSC agreed that the effects of purchase accounting entries related to pension and other post-retirement benefits would be recoverable in future rate proceedings. These amounts, which are related to EDG, were recorded as regulatory assets and are being amortized. The tax effects of these entries are reflected as deferred tax assets and liabilities and regulatory liabilities.

Annually we evaluate the discount rate, retirement age, compensation rate increases, expected return on plan assets, healthcare cost trend rate, and other actuarial assumptions related to pension benefit and post-retirement medical plan. When selecting the discount rate we utilize a modeling process that involves selecting a portfolio of above median, AA or better, bonds whose cash flows match the timing and extent of the expected cash flows of the Empire pension plan. In evaluating these assumptions, many factors are considered, including, current market conditions, asset allocations, changes in demographics and the views of leading financial advisors and economists. In evaluating the expected retirement age assumption, we consider the retirement ages of past employees eligible for pension and medical benefits together with expectations of future retirement ages. It is reasonably possible that changes in these assumptions will occur in the near term and, due to the uncertainties inherent in setting assumptions, the effect of such changes could be material to the Company’s consolidated financial statements. A roll forward technique is used to value the year ending pension obligations. The roll forward technique values the year-end obligation by rolling forward the beginning-of-year obligation using the demographic assumptions disclosed below. The economic assumptions are updated as of the end of the year. All of the benefit plans have been measured as of December 31, 2015, consistent with previous years. See Note 1.

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THE EMPIRE DISTRICT ELECTRIC COMPANY

Notes to Consolidated Financial Statements

Pensions

Our noncontributory defined benefit pension plan includes all employees meeting minimum age and service requirements. Effective on January 1, 2014, the plan was amended to include a cash balance benefit formula. Employees hired on or after January 1, 2014 will accrue benefits based on a cash balance methodology. Employees hired prior to January 1, 2014 were given a one-time option to convert to the cash balance methodology, or remain with our traditional average annual basic earnings formula, by December 31, 2014. Both benefit formulas allow for a lump sum distribution of vested benefits. Lump sum distributions totaled approximately $14.7 million and $15.3 million during 2016 and 2015, respectively, and did not require settlement accounting according to ASC 715.

Annual contributions to the plan are at least equal to the greater of either minimum funding requirements of ERISA or the accrued cost of the Plan, as required by the Missouri Public Service Commission.

Our net pension liability increased $3.8 million in 2016, which was recorded as an increase in regulatory assets as we believe it is probable of recovery through customer rates based on rate orders received in our jurisdictions. The increase in the liability is primarily due to a decrease in discount rates. Our contribution is estimated to be approximately $12.8 million for 2017. We expect future pension funding commitments to continue at least at the level of our accrued cost, as required by our regulator. The actual minimum funding requirements will be determined based on the results of the actuarial valuations and, in the case of 2018, the performance of our pension assets during 2017.

We also have a supplemental retirement program (“SERP”) for designated officers of the Company, which we fund from Company funds as the benefits are paid. The liability for this plan increased $1.5 million in 2016. Subsequent to the closing of the Merger, the SERP plan was frozen.

Expected benefit payments are as follows (in millions):

Year	Payments from Trust		Payments from Company Funds
2017	$	23.1	$	0.7
2018		21.9		0.6
2019		20.4		0.5
2020		20.3		1.0
2021		20.7		0.7
2022-2026		96.5		3.6

Other Postemployment Benefits (OPEB)

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 January 1, 2014 will be offered unsubsidized retiree healthcare benefits upon retirement.

Our net liability decreased $9.9 million in 2016, which was recorded as a decrease in regulatory assets as we believe it is probable of recovery through customer rates based on rate orders received in our jurisdictions. The decrease in the liability is due to a significant actuarial gain resulting from a revision to the medical cost trend rate and the adoption of a new mortality table as well as an increase in plan assets. Our funding policy is to contribute annually an amount at least equal to the actuarial cost of postemployment benefits. We expect to be required to fund approximately $1.0 million in 2017.

Estimated benefit payments are as follows (in millions):

Year	Payments from Trust		Expected Federal Subsidy		Payments from Company Funds
2017	$	2.8	$	0.3	$	0.2
2018		3.1		0.4		0.2
2019		3.4		0.4		0.2
2020		3.7		0.5		0.2
2021		3.9		0.5		0.2
2022-2026		23.7		3.4		0.9

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THE EMPIRE DISTRICT ELECTRIC COMPANY

Notes to Consolidated Financial Statements

The following tables set forth the Company’s benefit plans’ projected benefit obligations, the fair value of the plans’ assets and the funded status (in thousands).

Reconciliation of Projected Benefit	Pension						SERP						OPEB
Obligations:	2016			2015			2016			2015			2016			2015
Benefit obligation at beginning of  year	$	243,690		$	251,879		$	9,886		$	9,155		$	101,467		$	109,899
Service cost		7,533			7,442			176			158			3,271			3,713
Interest cost		10,581			10,278			434			382			4,668			4,670
Amendments		-			-			-			-			-			-
Net actuarial (gain)/loss		8,401			(708	)		1,216			557			(8,804	)		(14,358	)
Plan participant’s contribution		-			-			-			-			1,204			963
Benefits and expenses paid		(25,059	)		(25,201	)		(372	)		(366	)		(4,155	)		(3,839	)
Federal subsidy		-			-			-			-			110			419
Benefit obligation at end of year	$	245,146		$	243,690		$	11,340		$	9,886		$	97,761		$	101,467

Reconciliation of Fair Value of Plan	Pension						SERP				OPEB
Assets:	2016			2015			2016		2015		2016			2015
Fair value of plan assets at  beginning
of year	$	186,845		$	192,674		$	-	$	-	$	85,369		$	83,776
Actual return on plan assets –								-		-
gain/(loss)		10,205			(1,978	)						6,318			(955	)
Employer contribution		12,518			21,350			-		-		2,611			4,903
Benefits paid		(25,059	)		(25,201	)		-		-		(4,015	)		(3,670	)
Plan participant’s contribution		-			-			-		-		1,143			912
Federal subsidy		-			-			-		-		106			403
Fair value of plan assets at end of year	$	184,509		$	186,845		$	-	$	-	$	91,532		$	85,369

	Pension						SERP						OPEB
Reconciliation of Funded Status:	2016			2015			2016			2015			2016			2015
Fair value of plan assets	$	184,509		$	186,845		$	-		$	-		$	91,532		$	85,369
Projected benefit obligations		(245,146	)		(243,690	)		(11,340	)		(9,886	)		(97,761	)		(101,467	)
Funded status	$	(60,637	)	$	(56,845	)	$	(11,340	)	$	(9,886	)	$	(6,229	)	$	(16,098	)

The employee pension plan accumulated benefit obligation at December 31, 2016 and 2015 is presented in the following table (in thousands):

	Pension Benefits				SERP
	2016		2015		2016		2015
Accumulated benefit obligation	$	223,741	$	221,481	$	10,455	$	8,609

Amounts recognized in the balance sheet consist of (in thousands):

	Pension				SERP				OPEB
	2016		2015		2016		2015		2016		2015
Other deferred charges	$	-	$	-	$	-	$	-	$	143	$	-
Accounts payable and accrued liabilities	$	-	$	-	$	697	$	534	$	164	$	151
Pension and other postemployment benefit obligation	$	60,637	$	56,845	$	10,643	$	9,352	$	6,207	$	15,947

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THE EMPIRE DISTRICT ELECTRIC COMPANY

Notes to Consolidated Financial Statements

Net periodic benefit pension cost for 2016, 2015 and 2014, some of which is capitalized as a component of labor cost and some of which is deferred as a regulatory asset (see Note 3), is comprised of the following components (in thousands):

Net Periodic Pension Benefit	Pension									OPEB
Cost:	2016			2015			2014			2016			2015			2014
Service cost	$	7,533		$	7,442		$	6,467		$	3,271		$	3,713		$	2,601
Interest cost		10,581			10,278			10,819			4,668			4,670			4,360
Expected return on plan assets		(13,757	)		(13,567	)		(13,105	)		(5,498	)		(5,197	)		(4,801	)
Amortization of prior service
cost/(benefit)(1)		(630	)		(630	)		418			(1,011	)		(1,011	)		(1,011	)
Amortization of actuarial loss(1)		8,702			10,033			6,611			1,121			2,747			967
Net periodic benefit cost	$	12,429		$	13,556		$	11,210		$	2,551		$	4,922		$	2,116

Net Periodic Pension Benefit Cost:	SERP
	2016			2015			2014
Service cost	$	176		$	158		$	153
Interest cost		434			382			387
Expected return on plan assets		-			-			-
Amortization of prior service
cost/(benefit)(1)		(14	)		(42	)		(8	)
Amortization of actuarial loss(1)		569			597			504
Net periodic benefit cost	$	1,165		$	1,095		$	1,036

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

The tables below present other changes in plan assets and benefit obligations recognized in the regulatory asset accounts for the year (in thousands):

			Amount Recognized
Regulatory Assets	Beginning Balance 12/31/15		Current Year Actuarial Loss			Amortization of Actuarial Loss			Current Year Prior Service Credit		Amortization of Prior Service (Cost)/Credit		Ending Balance 12/31/16
Pension	$	82,889		11,952			(8,702	)		-		630	$	86,769
SERP	$	5,539		1,216			(569	)		-		14	$	6,200
OPEB	$	10,502		(9,624	)		(1,121	)		-		1,011	$	768

			Amount Recognized
Regulatory Assets	Beginning Balance 12/31/14		Current Year Actuarial Loss			Amortization of Actuarial Loss			Current Year Prior Service Credit		Amortization of Prior Service (Cost)/Credit		Ending Balance 12/31/15
Pension	$	77,456		14,836			(10,033	)		-		630	$	82,889
SERP	$	5,537		557			(597	)		-		42	$	5,539
OPEB	$	20,446		(8,208	)		(2,747	)		-		1,011	$	10,502

The following table presents the amount of net actuarial gains / losses, transition obligations / assets and prior period service costs in regulatory assets not yet recognized as a component of net periodic benefit cost. It also shows the amounts expected to be recognized in the subsequent year. The following table presents those items for the employee pension plan and other benefits plan at December 31, 2016, and the subsequent twelve-month period (in thousands):

	Pension Benefits							SERP				OPEB
		2016			Subsequent Period			2016			Subsequent Period		2016			Subsequent Period
Net actuarial loss	$	92,232		$	8,352		$	6,201		$	620	$	1,331		$	(41	)
Prior service cost (benefit)		(5,463	)		(630	)		(1	)		-		(563	)		(563	)
Total	$	86,769		$	7,722		$	6,200		$	620	$	768		$	(604	)

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THE EMPIRE DISTRICT ELECTRIC COMPANY

Notes to Consolidated Financial Statements

The measurement date used to determine the pension and other postemployment benefits is December 31. The assumptions used to determine the benefit obligation and the periodic costs are as follows:

Weighted-average assumptions used to determine the benefit obligation as of December 31:
	Pension Benefits						OPEB
	2016			2015			2016			2015
Discount rate		4.09	%		4.40	%		4.19	%		4.48	%
Rate of compensation increase		3.50	%		3.50	%		3.50	%		3.50	%

Weighted-average assumptions used to determine the net benefit cost (income) as of January 1:
	Pension Benefits									OPEB
	2016			2015			2014			2016			2015			2014
Discount rate		4.40	%		4.06	%		4.90	%		4.48	%		4.15	%		5.00	%
Expected return on plan assets		7.55	%		7.75	%		7.75	%		6.36	%		6.52	%		6.52	%
Rate of compensation increase		3.50	%		3.50	%		3.50	%		3.50	%		3.50	%		3.50	%

The expected long-term rate of return assumption was based on historical return and adjusted to estimate the potential range of returns for the current asset allocation. The assumed 2016 cost trend rate used to measure the expected cost of healthcare benefits and benefit obligation is 6.25%. Each trend rate decreases 0.25% through 2023 to an ultimate rate of 4.75% in 2023 and subsequent years.

The healthcare cost trend rate affects projected benefit obligations. A 1% change in assumed healthcare cost growth rates would have the following effects (in thousands):

	1% Increase		1% Decrease
Effect on total of service and interest cost	$	1,782	$	(1,351	)
Effect on post-retirement benefit obligation	$	16,345	$	(12,971	)

Fair value measurements of plan assets

See Note 15 for a discussion of fair value measurements. The Company believes that it is appropriate for the pension fund to assume a moderate degree of investment risk with diversification of fund assets among different classes (or types) of investments, as appropriate, as a means of reducing risk. Although the pension fund can and will tolerate some variability in market value and rates of return in order to achieve a greater long-term rate of return, primary emphasis is placed on preserving the pension fund’s principal. Full discretion is delegated to the investment managers to carry out investment policy within stated guidelines. The guidelines and performance of the managers are monitored by the Company’s Investment Committee. The following is a description of the valuation methodologies used for assets measured at fair value using significant other observable, or significant unobservable inputs.

Short-term investments:  Valued at cost, which approximates fair value.

Common/Collective trusts:  Valued at the fair value based on audited financials of the trusts.

U.S. corporate and foreign issue debt: Valued at quoted market prices when available in an active market. Ifquoted market prices are not available, then fair values are estimated by using pricing models, quoted prices of securities with similar characteristics, or discounted cash flows.

Equity long/short hedge funds: Valued at the net asset value reported in the annual audited financial statementsand updated monthly based on changes in the value of the underlying funds reported by the fund manager.

Pension plan assets

We utilize fair value in determining the market-related values for the different classes of our pension plan assets. The market-related value is determined based on smoothing actual asset returns in excess of (or less than) expected return on assets over a 5-year period.

The Company’s primary investment goals for pension fund assets are based around four basic elements:

1. Preserve capital,

2. Maintain a minimum level of return equal to the actuarial interest rate assumption,

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THE EMPIRE DISTRICT ELECTRIC COMPANY

Notes to Consolidated Financial Statements

3. Maintain a high degree of flexibility and a low degree of volatility, and

4. Maximize the rate of return while operating within the confines of prudence and safety.

Asset Allocation

We have adopted an investment strategy referred to as a de-risking glide path to increase the fixed income allocation as the plan’s funded status improves. As the pension plan reaches set funded status milestones, the plan’s assets will be rebalanced to shift more assets from equity to fixed income. Based on the plan’s progress with this strategy, the target investment allocation for pension fund assets is approximately 72% equities and 28% fixed income securities. However, these allocations are permitted to vary within the following ranges: 60%-80% for equities and 20%-40% for fixed income securities. Money market funds are permitted within the fixed income category. Investment managers may generally hold up to 10% cash in their portfolios although this limit may be exceeded if market conditions warrant.

The following fair value hierarchy table presents information about the pension fund assets measured at fair value as of December 31, 2016 and December 31, 2015 (in thousands):

	Fair Value Measurements as of December 31, 2016
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total		Percentage of Plan Assets
Short term investments	$	-	$	70	$	-	$	70		0.0	%
Equity securities
Common collective trusts		-		95,087		-		95,087		51.5	%
Fixed income
Common collective trust		-		52,146				52,146		28.3	%
Other types of investments
Common collective trust		-		35,372		-		35,372		19.2	%
Equity long/short hedge funds		-		-		1,834		1,834		1.0	%
	$	-	$	182,675	$	1,834	$	184,509		100.0	%

	Fair Value Measurements as of December 31, 2015
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total		Percentage of Plan Assets
Short term investments	$	-	$	71	$	-	$	71		0.0	%
Equity securities
Common collective trusts		-		88,110		-		88,110		47.2	%
Fixed income
Common collective trust		-		60,694		-		60,694		32.5	%
Other types of investments
Equity long/short hedge funds		-		-		37,970		37,970		20.3	%
	$	-	$	148,875	$	37,970	$	186,845		100.0	%

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THE EMPIRE DISTRICT ELECTRIC COMPANY

Notes to Consolidated Financial Statements

Fair Value Measurements Using Significant Unobservable Inputs (Level 3) – December 31,

	2016			2015
	Equity long/short hedge funds			Equity long/short hedge funds
Beginning Balance, January 1,	$	37,970		$	38,428
Actual return on plan assets:
Relating to assets still held at the reporting date		-			(458	)
Relating to assets sold during the period		534			-
Purchases		-			-
Sales		(36,670	)		-
Settlements		-			-
Transfers into and (out of) Level 3		-			-
Ending Balance, December 31,	$	1,834		$	37,970

Permissible Investments

Listed below are the investment vehicles specifically permitted:

Permissible Investments
Equity Oriented		Fixed Income Oriented and Real Estate
►	Common Stocks	►	Bonds (including US Government and Agencies)
►	Preferred Stocks (minimum "A-rated" by Moody's or S&P)	►	Corporate Bonds (minimum quality rating of Baa by Moody's or BBB by S&P)
►	American Depository Receipts	►	Comingled bond funds (25% max. allocation to high yield)
►	Convertible Preferred Stocks	►	Foreign Government Bonds
►	Convertible Bonds	►	GIC's, BIC's
►	Covered Options	►	Commercial Paper (rated A1 by S&P or P1 by Moody's)
►	Hedged Equity Funds of Funds	►	Certificates of Deposit in institutions with FDIC/FSLIC protection
		►	Money Market Funds/Bank STIF Funds
		►	Real Estate - Publicly Traded

The above assets can be held in commingled (mutual) funds as well as privately managed separate accounts.

Those investments prohibited by the Investment Committee without prior approval are:

Prohibited Investments Requiring Pre-approval

►	Privately Placed Securities	►	Warrants
►	Commodities Futures	►	Short Sales
►	Securities of Empire District (except in the hedged equity funds of funds or commingled funds)	►	Index Options
►	Restricted Stock	►	Letter Stock

OPEB plan assets

The Company’s primary investment goals for the component of the OPEB fund used to pay current benefits are liquidity and safety. The primary investment goals for the component of the OPEB fund used to accumulate funds to provide for payment of benefits after the retirement of plan participants are preservation of the fund with a reasonable rate of return. The target allocation for plan assets is 60% equities and 40% fixed income, although, at any given time, up to 10% of either category may be invested in cash equivalents. The 10% cash limitation may be exceeded if market conditions warrant. Allocations may also vary within the following ranges: 44%-76% equities and 36%-44% fixed income securities. The following fair value hierarchy table presents information about the OPEB fund assets measured at fair value as of December 31, 2016 and December 31, 2015 (in thousands):

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THE EMPIRE DISTRICT ELECTRIC COMPANY

Notes to Consolidated Financial Statements

	Fair Value Measurements as of December 31, 2016
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total			Percentage of Plan Assets
Equity securities
Common collective trusts	$	-	$	52,300	$	-	$	52,300			57.1	%
Fixed income
Common collective trusts		-		36,645		-		36,645			40.0	%
Other types of investments
Common collective trusts		-		2,727		-		2,727			3.0	%
	$	-	$	91,672	$	-		91,672
Payable for securities purchased								(140	)		-0.1	%
							$	91,532			100.0	%

	Fair Value Measurements as of December 31, 2015
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total			Percentage of Plan Assets
Equity securities
Common collective trusts	$	-	$	48,553	$	-	$	48,553			56.9	%
Fixed income
Common collective trusts		-		34,395		-		34,395			40.3	%
Other types of investments
Common collective trusts		-		2,556		-		2,556			3.0	%
	$	-	$	85,504	$	-		85,504
Payable for securities purchased								(135	)		-0.2	%
							$	85,369			100.0	%

The Company’s guideline in the management of this fund is to endorse a long-term approach, but not expose the fund to levels of volatility that might adversely affect the value of the assets. Full discretion is delegated to the investment managers to carry out investment policy within stated guidelines. The guidelines and performance of the managers are monitored by the Company’s Investment Committee.

35

THE EMPIRE DISTRICT ELECTRIC COMPANY

Notes to Consolidated Financial Statements

Permissible Investments

Listed below are the investment vehicles specifically permitted:

Permissible Investments

Equity		Fixed Income
►	Common Stocks	►	Cash-Equivalent Securities with a maturity of one-year or less, including: money market funds, US Government and Agency securities, certificates of deposit or banker's acceptances issued by domestic banks with FDIC protection and commercial paper rated A1 by S&P or P1 by Moody's
►	Preferred Stocks	►	Government Bonds
		►	Money Market Funds / Bank STIF Funds
		►	Certificates of Deposit in institutions with FDIC protection
		►	Corporate Bonds (minimum quality rating of A Baa by Moody's or BBB by S&P at time of issuance )

The above assets can be held in commingled (mutual) funds as well as privately managed separate accounts.

Listed below are those investments prohibited by the Investment Committee:

Prohibited Investments

►	Privately Placed Securities	►	Margin Transactions
►	Securities of Empire District	►	Options (other than "covered call options")
►	Derivatives	►	Lettered or Restricted Stock
►	Instrumentalities in violation of the Prohibited Transactions Standards of ERISA	►	Any other investment security which, in the opinion of the investment manager produces an imprudent risk to the fund

Employee Stock Purchase Plan

Prior to the closing of the Merger, our Employee Stock Purchase Plan (ESPP) permitted the granting to eligible employees options to purchase common stock at 90% of the lower of market value at date of grant or at date of exercise. The expense incurred related to this plan in each of the three years presented was immaterial. The look-back feature of this plan is valued at 90% of the Black-Scholes methodology plus 10% of the maximum subscription price. As of December 31, 2016 there were 707,737 shares available for issuance in this plan.

	2016		2015		2014
Subscriptions outstanding at December 31,		24,700		58,742		57,369
Maximum subscription price	$	30.29	$	21.09	$	21.43
Shares of stock issued		56,908		56,193		56,942
Stock issuance price	$	21.09	$	21.01	$	19.58

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

	2016			2015			2014
Weighted average fair value of grants	$	6.11		$	3.58		$	3.07
Risk-free interest rate		0.70	%		0.26	%		0.10	%
Dividend yield		3.10	%		4.40	%		4.30	%
Expected volatility (1)		27.00	%		21.00	%		14.00	%
Expected life in months		12			12			12
Grant date	6/1/2016			6/1/2015			6/2/2014

⁽¹⁾ One-year historic volatility

Pursuant to the Merger discussed above, the Employee Stock Purchase Plan (“ESPP”) was terminated on January 1, 2017.

In addition, subsequent to termination of the ESPP, we filed a Post-Effective Amendment to the Registration Statements on Form S-8 listed below (collectively, the “ESPP Registration Statements”) to deregister all securities that

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THE EMPIRE DISTRICT ELECTRIC COMPANY

Notes to Consolidated Financial Statements

were previously registered and remain unsold or otherwise unissued under the ESPP for which the Prior Registration Statements had remained in effect.

1. Registration Statement Number 33-34807 filed on May 9, 1990.

2. Registration Statement Number 333-130076 filed on December 1, 2005.

3. Registration Statement Number 2-53621 filed on May 8, 1975.

4. Registration Statement Number 2-67598 filed on April 30, 1980.

5. Registration Statement Number 333-197981 filed on August 8, 2014.

As a result of the Merger, Empire has terminated the offering of its securities pursuant to the ESPP Registration Statements. Any of the securities that were registered for issuance under the ESPP Registration Statements that remain unsold at the termination of the offering were removed from registration.

Subsequent to the Merger, all of the unused amounts (24,700 shares) credited to participant accounts through payroll deduction were refunded to participants, together with interest as provided by the Plan.

401(k) Plan and ESOP

Our Employee 401(k) Plan and ESOP (the 401(k) Plan) allows participating employees to defer up to 25% of their annual compensation up to an Internal Revenue Service specified limit. For employees participating in the cash balance formula of the pension plan, discussed above, we match 100% of their deferrals, not to exceed 6% of the employee’s eligible compensation. Prior to the closing of the Merger, the first 3% of the matching contribution was made in shares of our common stock with the remaining portion made by contributing cash. Prior to the closing of the Merger, for employees remaining with the traditional average annual basic earnings formula of the pension plan, we matched 50% of their deferrals by contributing shares of our common stock, with such matching contributions not to exceed 3% of the employee’s eligible compensation. We record the compensation expense at the time the matching contributions are made to the plan. At December 31, 2016, there were 78,453 shares available to be issued.

	2016		2015		2014
Shares contributed		51,163		66,783		60,049

Effective November 1, 2016, the 401(k) Plan was amended to allow employer matching contributions to be made in either cash or employer stock. Subsequent to the Merger, matching employer contributions will be made in cash.

8. EQUITY COMPENSATION

Prior to the closing of the Merger, we maintained several stock-based awards and programs, which are described below. Performance-based restricted stock awards and time-vested restricted stock are valued as liability awards, in accordance with fair value guidelines. We allow employees to elect to have taxes in excess of the minimum statutory requirements withheld from their awards and, therefore, the awards are classified as liability instruments under the ASC guidance on share based payment. Awards treated as liability instruments must be revalued each period until settled, and cost is accrued over the requisite service period and adjusted to fair value at each reporting period until settlement or expiration of the award.

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

	2016		2015		2014
Compensation expense	$	6,583	$	4,279	$	3,688
Tax benefit recognized		2,457		1,576		1,359

Stock Incentive Plans

Our 2006 Stock Incentive Plan (the “2006 SIP”), which expired on December 31, 2015, was replaced by the 2015 Stock Incentive Plan (the “2015 SIP”). The 2015 SIP was adopted by shareholders at the annual meeting on May 1,

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THE EMPIRE DISTRICT ELECTRIC COMPANY

Notes to Consolidated Financial Statements

2014 and provides for grants of up to 500,000 shares of common stock through January 2025. At December 31, 2016 there were 459,093 shares available to be issued. The 2015 SIP permits (and the 2006 SIP permitted) grants of stock options and restricted stock to qualified employees and permits Directors and, if approved by the Compensation Committee of the Board of Directors, qualified employees to receive common stock in lieu of cash. Certain executive officers and other senior managers applied to receive annual incentive awards related to 2014, 2015 and 2016 performance in the form of Empire common stock rather than cash. These requests were granted by the Compensation Committee of the Board of Directors under the terms of our 2006 and 2015 SIPs. The terms and conditions of any option or stock grant are determined by the Board of Directors Compensation Committee, within the provisions of these Stock Incentive Plans.

Pursuant to the Merger discussed above, the 2006 SIP and the 2015 SIP were terminated on January 1, 2017.

We filed a Post-Effective Amendment to the Registration Statements on Form S-8 listed below (collectively, the “SIP Registration Statements”) to deregister all securities that were previously registered and remain unsold or otherwise unissued under the (i) 2006 Stock Incentive Plan and (ii) 2015 Stock Incentive Plan, as the case may be, and for which the SIP Registration Statements had remained in effect.

1. Registration Statement Number 333-130075 filed on December 1, 2005.

2. Registration Statement Number 333-197982 filed on August 8, 2014.

As a result of the Merger, Empire has terminated the offering of its securities pursuant to the SIP Registration Statements. Any of the securities that were registered for issuance under the SIP Registration Statements that remain unsold at the termination of the offering were removed from registration.

Time-Vested Restricted Stock Awards

Prior to the Merger, time-vested restricted stock awards that vest after a three-year period were granted to qualified individuals. No dividend rights accumulated during the vesting period. Time-vested restricted stock was valued at an amount equal to the fair market value of our common stock on the date of grant. If employment terminated during the vesting period because of death, retirement or disability, the participant was entitled to a pro-rata portion of the time-vested restricted stock awards such participant would otherwise have earned, to be 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. Our Merger with Liberty Central triggered a change in control and the resulting distribution is further described below.

The fair value measurements for each grant year are noted in the following table:

	Fair Value of Grants Outstanding at December 31
	2016		2015
Total unrecognized compensation cost (in millions)	$	0.0	$	0.4
Recognition period		-		0.1 years to 2.1 years
Fair value	$	34.00	$	25.17

A summary of time-vested restricted stock activity under the plan for 2016, 2015 and 2014 is presented in the table below:

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THE EMPIRE DISTRICT ELECTRIC COMPANY

Notes to Consolidated Financial Statements

	2016					2015					2014
	Number of Shares			Weighted Average Grant Date Fair Value		Number of Shares			Weighted Average Grant Date Fair Value		Number Of Shares			Weighted Average Grant Date Fair Value
Outstanding at January 1,		55,600		$	24.60		41,000		$	21.89		24,900		$	21.42
Granted		18,400		$	29.53		19,000		$	30.40		22,600		$	22.40
Distributed		(18,500	)	$	21.36		(1,654	)	$	21.92		(4,010	)	$	21.77
Forfeited		0			-		(2,746	)	$	25.91		(2,490	)	$	21.99
Outstanding at December 31,		55,500		$	27.31		55,600		$	24.60		41,000		$	21.89

Pursuant to the Merger Agreement, and concurrent with the closing of the Merger, 37,162 shares of time-vested restricted stock grants that were outstanding immediately prior to the closing of the Merger were cancelled and converted into the right to receive a lump-sum cash payment, payable in accordance with the Merger Agreement. The cancellation and conversion of these shares are not included in the table above. (See Note 17 for further discussion of the Merger Agreement).

Performance-Based Restricted Stock Awards

Prior to the Merger, performance-based restricted stock awards were granted to qualified individuals 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. The performance measure for the award was the total return to our shareholders over a three-year period compared with an investor-owned utility peer group. The threshold level of performance under the 2014, 2015 and 2016 grants was set at the 20th percentile level of the peer group, target at the 50th percentile level, and the maximum at the 80th percentile level. Shares would be earned at the end of the three-year performance period as follows: 100% of the target number of shares if the target level of performance is reached, 50% if the threshold is reached, and 200% if the percentile ranking is at or above the maximum, with the number of shares interpolated between these levels. However, no shares would be payable if the threshold level is not reached.

If employment terminated during the performance period because of death, retirement, or disability, the individual was entitled to a pro-rata portion of the performance-based restricted stock awards such individual would otherwise have earned. If employment was terminated during the performance period for reasons other than those listed above, the performance-based restricted stock awards would be forfeited on the date of the termination unless the Compensation Committee of the Board of Directors determined, in its sole discretion, that the individual was 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. Our Merger with Liberty Central triggered a change in control and the distribution is described below.

The fair value of the outstanding restricted stock awards was estimated as of December 31, 2015 and 2014 using a Monte Carlo option valuation model. Pursuant to the Merger Agreement, shares were revalued during 2016 to $34.00 per share in accordance with the Merger Agreement. The assumptions used in the model for each grant year are noted in the following table:

	Fair Value of Grants Outstanding at December 31
	2015		2014
Risk-free interest rate	0.65% to 1.06%		0.25% to 0.67%
Expected volatility of Empire stock		18.7%		14.5%
Expected volatility of peer group stock	14.5% to 34.4%		12.4% to 24.8%
Expected dividend yield on Empire stock		3.7%		3.5%
Expected forfeiture rates		3%		3%
Plan cycle	3 years		3 years
Fair value percentage	115.0% to 182.0%		140.0% to 157.0%
Weighted average fair value per share	$	41.73	$	43.80

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THE EMPIRE DISTRICT ELECTRIC COMPANY

Notes to Consolidated Financial Statements

Non-vested performance-based restricted stock awards (based on target number) as of December 31, 2016, 2015 and 2014 and changes during the year ended December 31, 2016, 2015 and 2014 were as follows:

	2016					2015					2014
	Number of Shares			Weighted Average Grant Date Fair		Number of Shares			Weighted Average Grant Date Fair		Number Of Shares			Weighted Average Grant Date Fair
				Value					Value					Value
Outstanding at January 1,		69,021		$	24.38		63,300		$	21.74		47,200		$	21.39
Target shares granted		22,400		$	29.53		21,800		$	30.40		27,000		$	22.40
Shares issued in excess of target		18,403		$	21.36		3,653		$	20.97		-			-
Shares awarded		(43,036	)	$	21.36		(13,653	)	$	20.97		-			-
Forfeited shares		-			-		(6,079	)	$	24.10		-			-
Target shares not awarded		-			-		-			-		(10,900	)	$	21.84
Nonvested at December 31,		66,788		$	27.22		69,021		$	24.38		63,300		$	21.74

At December 31, 2016 and 2015, unrecognized compensation expense related to estimated outstanding awards was $0.0 million and $0.7 million, respectively.

Pursuant to the Merger Agreement, and concurrent with the closing of the Merger, 42,600 shares of performance-based restricted stock granted under the 2006 SIP and the 2015 SIP that were outstanding immediately prior to the closing of the Merger were cancelled and converted into the right to receive a lump-sum cash payment, payable in accordance with the Merger Agreement. The cancellation and conversion of these shares are not included in the table above. (See Note 17 for further discussion of the Merger Agreement).

Stock Unit Plan for Directors

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

As of December 31, 2016, a total of 900,000 shares were authorized under the SUP. Each common stock unit earns dividends in the form of common stock units and can be redeemed for shares of common stock. Pursuant to the Merger Agreement, and concurrent with the closing of the Merger, each stock unit credited under the SUP that was outstanding immediately prior to the closing of the Merger was cancelled and converted into the right to receive payment of an amount in cash equal to the merger consideration (as defined in the Merger Agreement) at the payment date elected or otherwise provided pursuant to the SUP, together with interest on such amount at the “U.S. Prime Rate” as quoted by the Wall Street Journal in effect at the Closing Date for the period, if any, from the Closing Date until the date of payment of such amount.

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

	2016		2015
Shares accrued to directors’ accounts(1)		211,588	157,672
Shares available for issuance		656,737	677,980

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

	2016		2015		2014
Units accrued for service and dividends(1)		47,747		30,595		30,765
Units redeemed for common stock		21,246		37,008		21,083

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THE EMPIRE DISTRICT ELECTRIC COMPANY

Notes to Consolidated Financial Statements

⁽¹⁾ As a result of the timing of the closing of the Merger, 20,331 units were accrued to directors’ accounts on December 31, 2016 for service and dividends.

9. INCOME TAXES

Income tax expense components for the years ended December 31 are as follows (in thousands):

	2016			2015			2014
Current income taxes:
Federal	$	739		$	-		$	(2,350	)
State		-			-			(123	)
TOTAL		739			-			(2,473	)
Deferred income taxes:
Federal		33,708			29,722			36,620
State		4,801			4,233			5,216
TOTAL		38,509			33,955			41,836
Investment tax credit amortization		(143	)		(143	)		(143	)
TOTAL INCOME TAX EXPENSE	$	39,105		$	33,812		$	39,220

Deferred Income Taxes

Deferred tax assets and liabilities are reflected on our consolidated balance sheets as follows (in thousands):

	December 31,
Deferred Income Taxes	2016		2015
NET DEFERRED TAX LIABILITIES	$	429,666	$	396,542

Temporary differences related to deferred tax assets and deferred tax liabilities are summarized as follows (in thousands):

	December 31,
Temporary Differences	2016		2015
Deferred tax assets:
Plant related basis differences	$	28,531	$	27,347
Net operating loss (NOL)		17,869		9,055
Regulated liabilities related to income taxes		12,939		13,142
Disallowed plant costs		1,612		1,699
Gains on hedging transactions		1,131		1,195
Pensions and other post-retirement benefits		-		-
Carry forward of income tax credit		8,675		8,675
Other		2,289		1,550
Total deferred tax assets	$	73,046	$	62,663
Deferred tax liabilities:
Depreciation, amortization and other plant related differences	$	426,137	$	382,897
Regulated assets related to income		38,927		38,615
Loss on reacquired debt		3,316		3,572
Amortization of intangibles		11,207		10,248
Pensions and other post-retirement benefits		7,957		7,112
Deferred construction accounting costs		5,576		5,711
Other		9,592		11,050
Total deferred tax liabilities		502,712		459,205
NET DEFERRED TAX LIABILITIES	$	429,666	$	396,542

Effective Income Tax Rates

The difference between income taxes and amounts calculated by applying the federal legal rate to income tax expense for continuing operations were as follows:

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THE EMPIRE DISTRICT ELECTRIC COMPANY

Notes to Consolidated Financial Statements

Effective Income Tax Rates	2016			2015			2014
Federal statutory income tax rate		35.0	%		35.0	%		35.0	%
Increase (decrease) in income tax rate resulting from:
State income tax (net of federal benefit)		3.1			3.1			3.1
Investment tax credit amortization		(0.4	)		(0.2	)		(0.1	)
Effect of ratemaking on property related differences		(0.6	)		(1.4	)		(1.7	)
Other		0.8			0.9			0.6
EFFECTIVE INCOME TAX RATE		37.9	%		37.4	%		36.9	%

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

The “Protecting Americans from Tax Hikes” Act (the “Act”) was signed into law on December 18, 2015. The Act restored several expired business tax provisions, including bonus depreciation for 2015 and 2016. Because of the reinstatement of bonus depreciation, we anticipate making no material income tax payments in 2017.

We generated a $74.1 million tax net operating loss (NOL) during 2014, mainly due to bonus depreciation. We elected to carry forward the NOL, which, if unused, will expire in 2034. We utilized $43.8 million of the 2014 NOL on our 2015 return. We estimate generating an additional NOL of $13.8 million in our 2016 tax year assuming we would elect to utilize bonus depreciation on the Riverton 12 facility placed in service during the year. As of December 31, 2016, we estimate there is $17.9 million of deferred tax assets remaining to be utilized related to the tax NOLs.

In 2010, we received $17.7 million of investment tax credits based on our investment in Iatan 2, which, if unused, will expire in 2030. We utilized $9.0 million of these credits on our 2013 tax return. Due to the passage of the Act, we estimate we will not be able to use the remaining credits on our 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.

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

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

10. COMMONLY OWNED FACILITIES

Iatan

We own a 12% undivided interest in the coal-fired Units No. 1 and No. 2 at the Iatan Generating Station located near Weston, Missouri, 35 miles northwest of Kansas City, Missouri, as well as a 3% interest in the site and a 12% interest in certain common facilities. We are entitled to 12% of each unit’s available capacity and are obligated to pay for a like percentage of the operating costs of the units. KCP&L and KCP&L Greater Missouri Operations Co. own 70% and 18% respectively, of Unit 1, and 54% and 18%, respectively, of Unit 2. KCP&L operates the units for the joint owners.

At December 31, 2016 and 2015, our property, plant and equipment accounts included the amounts in the following chart (in millions):

Iatan	2016		2015
Cost of ownership in plant in service	$	381.3	$	380.2
Accumulated Depreciation	$	112.3	$	105.3
Expenditures(1)	$	27.1	$	26.9

⁽¹⁾ Recognized in operating, maintenance, and fuel expenditures excluding depreciation expense.

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Notes to Consolidated Financial Statements

State Line Combined Cycle Unit

We share joint ownership with Westar Generating, Inc, (“WGI”), a subsidiary of Westar Energy, Inc., of a nominal 500-megawatt combined cycle unit at the State Line Power Plant (the “State Line Combined Cycle Unit”). We are responsible for the operation and maintenance of the State Line Combined Cycle Unit, and are entitled to 60% of the available capacity and are responsible for approximately 60% of its costs.

At December 31, 2016 and 2015, our property, plant and equipment accounts included the amounts in the following chart (in millions):

State Line Combined Cycle Unit	2016		2015
Cost of ownership in plant in service	$	162.8	$	163.0
Accumulated Depreciation	$	44.8	$	43.5
Expenditures(1)	$	36.6	$	40.7

⁽¹⁾ Recognized in operating, maintenance, and fuel expenditures excluding depreciation expense.

Plum Point Energy Station

We own a 7.52% undivided interest in the coal-fired Plum Point Energy Station located near Osceola, Arkansas. We are entitled to 7.52% of the station’s capacity, and are obligated to pay for a like percentage of the station’s operating costs.

At December 31, 2016 and 2015, our property, plant and equipment accounts included the amounts in the following chart (in millions):

Plum Point Energy Station	2015		2014
Cost of ownership in plant in service	$	109.2	$	109.1
Accumulated Depreciation	$	13.8	$	11.9
Expenditures(1)	$	10.0	$	9.6

⁽¹⁾ Recognized in operating, maintenance and fuel expenditures excluding depreciation expense.

All of the dollar amounts listed above represent our ownership share of costs.

11. COMMITMENTS AND CONTINGENCIES

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 merger with Liberty Central.

On March 24, 2016, a purported shareholder of Empire filed a complaint styled as a class action lawsuit. 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, 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. 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 continue to vigorously deny that they committed any violation of law or engaged in any wrongful acts alleged in the complaint.

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THE EMPIRE DISTRICT ELECTRIC COMPANY

Notes to Consolidated Financial Statements

The proposed settlement will provide for the release of any and all claims arising out of or relating to the Merger. The Company has accrued $0.5 million as an estimate of the potential settlement liability. The settlement is subject to final Court approval following notice to the class members.

The outcome of the lawsuit cannot be predicted with any certainty. An injunction could result in the unwinding of the Merger, although the Company believes that to be unlikely. 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 December 31, 2016 (in millions).

	Firm physical gas and transportation contracts		Coal and coal transportation contracts
January 1, 2017 through December 31, 2017	$	13.9	$	10.6
January 1, 2018 through December 31, 2019		34.8		6.3
January 1, 2020 through December 31, 2021		30.3		-
January 1, 2022 and beyond		41.8		-

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 December 31, 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 $267.5 million through August 31, 2039, the end date of the agreement.

We have a long-term purchased power agreement, which expires in 2028, with Cloud County Windfarm, LLC, owned by EDP Renewables North America LLC, Houston, Texas to purchase the energy generated at the approximately 105-megawatt Phase 1 Meridian Way Wind Farm located in Cloud County, Kansas. Annual payments are contingent upon output of the facility and can range from zero to a maximum of approximately $14.6 million based on a 20-year average cost.

We also have a long-term contract, which expires in 2025, 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.

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THE EMPIRE DISTRICT ELECTRIC COMPANY

Notes to Consolidated Financial Statements

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 the operating lease obligations shown below.

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. Final construction costs through December 31, 2016 were $168.1 million for the project, excluding AFUDC. This amount was included in our five-year capital expenditure plan.

In December 2014 we completed an environmental retrofit at our Asbury plant. The retrofit project included the installation of a pulse-jet fabric filter (baghouse), circulating dry scrubber and powder activated carbon injection system. This new equipment enables us to comply with the Mercury and Air Toxics Standard (MATS). Final costs were approximately $112.1 million, excluding AFUDC.

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 December 31, 2016.

Our lease obligations over the next five years are as follows (in thousands):

	Capital Leases		Operating Leases
2017	$	551	$	696
2018		551		648
2019		550		485
2020		547		-
2021		547		-
Thereafter		1,913		-
Total minimum payments		4,659	$	1,829
Less amount representing interest		1,080
Present value of net minimum lease payments	$	3,579

Expenses incurred related to operating leases were $0.8 million for 2016, 2015, and 2014, excluding payments for wind generated purchased power agreements. The accumulated amount of amortization for our capital leases was $2.2 million and $1.9 million at December 31, 2016 and 2015, respectively.

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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THE EMPIRE DISTRICT ELECTRIC COMPANY

Notes to Consolidated Financial Statements

Compliance Plan

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

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 continued 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 and the compliance methods yet to be chosen by the jurisdictions in which we operate if the rule is upheld. 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) SteamElectric 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.

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THE EMPIRE DISTRICT ELECTRIC COMPANY

Notes to Consolidated Financial Statements

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 $15.5 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 December 28, 2016, the Missouri Department of Natural Resources (MDNR) approved our permit application to construct a utility waste landfill on a 217 acre site adjacent to the Asbury plant.

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 CleanWater 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 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 December 31, 2016, we had processed 912 solar rebate applications resulting in solar rebate-related costs totaling approximately $11.2 million under the new tariff. We have recorded the $11.2 million as a regulatory asset (See Note 3 – Regulatory Matters). The law provides a number of methods that may be utilized to recover the associated expenses. We expect any costs to be recoverable in rates.

Legislation was 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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THE EMPIRE DISTRICT ELECTRIC COMPANY

Notes to Consolidated Financial Statements

12. SEGMENT INFORMATION

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

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

	For the year ended December 31,
	2016
Statement of Income Information:	Electric		Gas		Other		Eliminations			Total
Operating Revenues(1)	$	568,766	$	36,743	$	8,420	$	(1,379	)	$	612,550
Depreciation and amortization		80,026		4,029		1,951		-			86,006
Federal and state income taxes		37,250		621		1,234		-			39,105
Operating income		99,611		4,879		1,930		-			106,420
Interest income		116		35		94		(115	)		130
Interest expense		42,541		3,872		-		(115	)		46,298
Income from AFUDC (debt and equity)		5,125		11		-		-			5,136
Income from continuing operations	$	61,013	$	1,008	$	2,006	$	-		$	64,027
Capital Expenditures	$	114,279	$	4,035	$	952	$	-		$	119,266

⁽¹⁾ The Electric Segment includes SPP Integrated Marketplace net revenues of $24.1 million.

	2015
Statement of Income Information:	Electric		Gas		Other		Eliminations			Total
Operating Revenues(1)	$	555,085	$	41,702	$	10,165	$	(1,379	)	$	605,573
Depreciation and amortization		74,732		3,923		1,895		-			80,550
Federal and state income taxes		31,123		800		1,889		-			33,812
Operating income		88,124		5,153		3,024		-			96,301
Interest income		133		36		47		(71	)		145
Interest expense		41,307		3,867		-		(71	)		45,103
Income from AFUDC (debt and equity)		7,681		14		-		-			7,695
Income from continuing operations	$	52,240	$	1,287	$	3,070	$	-		$	56,597
Capital Expenditures	$	169,111	$	5,190	$	2,223	$	-		$	176,524

⁽¹⁾ The Electric Segment includes SPP Integrated Marketplace net revenues of $15.0 million.

	2014
Statement of Income Information:	Electric		Gas		Other		Eliminations			Total
Operating Revenues	$	592,491	$	51,842	$	9,302	$	(1,305	)	$	652,330
Depreciation and amortization		67,534		3,760		1,891		-			73,185
Federal and state income taxes		35,737		1,840		1,643		-			39,220
Operating income		90,488		6,775		2,736		-			99,999
Interest income		37		25		21		(32	)		51
Interest expense		37,911		3,861		-		(32	)		41,740
Income from AFUDC (debt and equity)		9,833		84		-		-			9,917
Income from continuing operations	$	61,467	$	2,965	$	2,671	$	-		$	67,103
Capital Expenditures	$	212,866	$	7,836	$	2,151	$	-		$	222,853

⁽¹⁾ The Electric Segment includes SPP Integrated Marketplace net revenues of $41.9 million.

	December 31,
Balance Sheet Information:	2016
	Electric		Gas (1)		Other		Eliminations			Total
Total assets	$	2,362,869	$	130,434	$	39,545	$	(53,567	)	$	2,479,281

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THE EMPIRE DISTRICT ELECTRIC COMPANY

Notes to Consolidated Financial Statements

	December 31,
Balance Sheet Information:	2015
	Electric		Gas (1)		Other		Eliminations			Total
Total assets	$	2,331,705	$	127,358	$	38,300	$	(50,718	)	$	2,446,645

⁽¹⁾ Includes goodwill of $39,492 at December 31, 2016 and 2015.

13. SELECTED QUARTERLY INFORMATION (UNAUDITED)

The following is a summary of quarterly results for 2016 and 2015 (dollars in thousands except per share amounts):

	Quarters
Quarterly Results for 2016	First		Second		Third		Fourth
Operating revenues(1)	$	151,315	$	139,320	$	175,354	$	146,560
Operating income	$	23,243	$	19,377	$	39,014	$	24,786
Net Income	$	14,009	$	9,225	$	27,505	$	13,288
Basic Earnings Per Share	$	0.32	$	0.21	$	0.62	$	0.30
Diluted Earnings Per Share	$	0.32	$	0.21	$	0.62	$	0.30

⁽¹⁾ Operating revenue for the first, second, third and fourth quarters of 2016 include SPP IM net revenues of $3.1 million, $6.3 million, $7.7 million, and $7.0 million, respectively.

	Quarters
Quarterly Results for 2015	First		Second		Third		Fourth
Operating revenues(1)	$	164,544	$	134,557	$	169,714	$	136,758
Operating income	$	24,713	$	16,047	$	35,783	$	19,757
Net Income	$	14,637	$	6,770	$	25,285	$	9,905
Basic Earnings Per Share	$	0.34	$	0.16	$	0.58	$	0.23
Diluted Earnings Per Share	$	0.34	$	0.15	$	0.58	$	0.23

⁽¹⁾ Operating revenue for the first, second, third and fourth quarters of 2015 include SPP IM net revenues of $4.7 million, $3.4 million, $4.0 million, and $2.9 million, respectively

The sum of the net income and quarterly earnings per share of common stock may not equal the net income and earnings per share of common stock as computed on an annual basis due to rounding.

14. 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 acquire Transmission Congestion Rights (TCR) in an effort to mitigate the cost of power we purchase from the SPP 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 financial derivative instruments are recognized at fair value on the balance sheet (see Note 1). 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 ASC guidance on regulated operations, given that those gains or losses are probable of refund or recovery, respectively, through our fuel adjustment mechanisms.

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THE EMPIRE DISTRICT ELECTRIC COMPANY

Notes to Consolidated Financial Statements

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

ASSET DERIVATIVES		2016		2015
Non-designated hedging instruments due to regulatory accounting	Balance Sheet Classification	Fair Value		Fair Value
Natural gas contracts, gas segment	Current assets	$	326	$	2
	Non-current assets and deferred charges- Other		-		16
Natural gas contracts, electric segment	Current assets		3,223		-
	Non-current assets and deferred charges- Other		684		-
Transmission congestion rights, electric segment	Current assets		2,492		1,293
Total derivatives assets		$	6,725	$	1,311
LIABILITY DERIVATIVES		2016		2015
Non-designated as hedging instruments due to regulatory accounting	Balance Sheet Classification	Fair Value		Fair Value
Natural gas contracts, gas segment	Current liabilities	$	17	$	282
	Non-current liabilities and deferred credits		-		66
Natural gas contracts, electric segment	Current liabilities		1,126		4,190
	Non-current liabilities and deferred credits		1,239		3,630
Transmission congestion rights, electric segment	Current liabilities		-		-
Total derivatives liabilities		$	2,382	$	8,168

Electric Segment

At December 31, 2016, approximately $2.1 million of unrealized gains are applicable to financial instruments which will settle within the next twelve months.

There were no “mark-to-market” pre-tax gains/ (losses) from ineffective portions of our hedging activities for the electric segment for the years ended December 31, 2016 and 2015, respectively.

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 years ended December 31 (in thousands):

Non-Designated Hedging Instruments – Due to Regulatory Accounting Electric Segment	Balance Sheet Classification of Gain/(Loss) on Derivative	Amount of Gain/(Loss) Recognized on Balance Sheet
		2016		2015
Commodity contracts	Regulatory (assets)/liabilities	$	6,810	$	(6,853	)
Transmission congestion rights	Regulatory (assets)/liabilities		6,761		4,970
Total – Electric Segment		$	13,571	$	(1,883	)

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THE EMPIRE DISTRICT ELECTRIC COMPANY

Notes to Consolidated Financial Statements

Non-Designated Hedging Instruments – Due to Regulatory Accounting Electric Segment	Statement of Operations Classification of Gain/(loss) on Derivative	Amount of Gain/(Loss) Recognized in Income on Derivative
		2016			2015
Commodity contracts	Fuel and purchased power expense	$	(3,269	)	$	(8,115	)
Transmission congestion rights	Fuel and purchased power expense		5,508			7,468
Total – Electric Segment		$	2,239		$	(647	)

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

As of December 31, 2016, the following volumes and percentage of our anticipated volume of natural gas usage for our electric operations for 2017 and 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
2017		61	%		1,702,900		8,460,000	$	3.285	Up to 100%
2018		41	%		565,000		5,960,000	$	3.164		60	%
2019		21	%		1,240,000		2,460,000	$	2.781		40	%
2020		11	%		1,240,000		500,000	$	2.786		20	%
2021		0	%		-		-	$	-		10	%

At December 31, 2016, the following transmission congestion rights (TCR) have been obtained from TCR auctions to hedge congestion costs in the SPP Integrated Marketplace:

Year	Monthly MWH Hedged		$ Value
2017		5,324	$	2,492

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 December 31, 2016 we had 1.2 million Dths in storage on the three pipelines that serve our customers. This represents 57% of our storage capacity.

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THE EMPIRE DISTRICT ELECTRIC COMPANY

Notes to Consolidated Financial Statements

The following table sets forth our long-term hedge strategy of mitigating price volatility for our customers by hedging a minimum of expected gas usage for the current winter season and the next two winter seasons by the beginning of the ACA year at September 1 and illustrates our hedged position as of December 31, 2016 (Dth in thousands).

	Minimum %			Dth Hedged		Dth Hedged
Season	Hedged			Financial		Physical		Dth in Storage		Actual % Hedged
Current		50	%		120		-		1,158		68	%
Second	Up to 50%				280		-		-		9	%
Third	Up to 20%				-		-		-		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 the years ended December 31 (in thousands):

Non-Designated Hedging Instruments Due to Regulatory Accounting – Gas Segment	Balance Sheet Classification of Loss on Derivative	Amount of Gain/(Loss) Recognized on Balance Sheet
		2016		2015
Commodity contracts	Regulatory (assets)/liabilities	$	920	$	(447	)
Total – Gas Segment		$	920	$	(447	)

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 December 31, 2016 and have posted no collateral with counterparties in the normal course of business. Amounts reported as margin deposit assets represent our funds held on deposit for our contracts held with our NYMEX broker and other financial contracts with other counterparties that resulted from us exceeding agreed-upon credit limits established by the counterparties. The following table depicts our margin deposit assets at the dates shown. There were no margin deposit liabilities at these dates.

	December 31, 2016		December 31, 2015
(in millions)
Margin deposit assets	$	1.5	$	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 years ended December 31, 2016 and December 31, 2015, we did not hold any collateral posted by our counterparties. The only collateral we have posted is our margin deposit assets described above. We have elected not to offset our margin deposit assets against any of our eligible commodity contracts.

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THE EMPIRE DISTRICT ELECTRIC COMPANY

Notes to Consolidated Financial Statements

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

Our TCR positions, which are acquired on the SPP Integrated Marketplace, 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 December 31:

				Fair Value Measurements at Reporting Date Using
($ in 000’s)	Assets/(Liabilities) at Fair Value			Quoted Prices in Active Markets for Identical Assets (Level 1)				Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Description
				December 31, 2016
Derivative assets	$	6,725			$	4,233		$	2,492	$	-
Derivative liabilities	$	(2,382	)		$	(2,382	)	$	-	$	-
				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 December 31, 2016 and 2015 was $826 million and $859 million, compared to a fair market value of approximately $839 million and $815 million, respectively. 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 December 31, 2016 or that will be realizable in the future.

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Notes to Consolidated Financial Statements

16. REGULATED OPERATING EXPENSE

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

	December 31,
	2016		2015		2014
Power operation expense (other than fuel)	$	17,110	$	18,263	$	16,089
Electric transmission and distribution expense		27,751		28,893		27,919
Natural gas transmission and distribution expense		2,543		2,699		2,362
Customer accounts & assistance expense		11,123		10,937		11,239
Employee pension expense (1)		11,859		10,786		10,590
Employee healthcare plan (1)		10,125		10,162		9,147
General office supplies and expense		17,209		14,438		15,024
Administrative and general expense		14,580		14,863		14,385
Bad debt expense		1,452		2,080		3,420
Regulatory reversal of gain on sale of assets		-		-		44
Miscellaneous expense		377		430		472
TOTAL	$	114,129	$	113,551	$	110,691

(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.

17. MERGERS AND ACQUISITIONS

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, a Delaware corporation (Liberty), and Merger Sub, a Kansas corporation, 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). The Merger closed on January 1, 2017. 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) was cancelled and converted automatically into the right to receive $34.00 in cash, without interest.

As discussed below, all required regulatory approvals and consents were received in 2016. In connection with each of the regulatory approvals received, Liberty Utilities Co. 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.

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

On June 29, 2016, we and Algonquin filed a joint notice with the Committee on Foreign Investment in the United States (CFIUS) and we and Algonquin each filed notification with the Federal Trade Commission and U.S. Department of Justice under the Hart-Scott-Rodino Act (HSR Act). The 30-day waiting period under the HSR Act expired on July 29, 2016 without receiving a request for additional information. We were notified by the U.S. Department of the Treasury on August 8, 2016, that CFIUS had determined no unresolved national security concerns existed with respect to the Merger and their actions were concluded with no request for additional information.

The Federal Communications Commission (FCC) concluded a review of license transfers resulting from the Merger with no actions taken.

Pursuant to the Merger Agreement, and subsequent to the closing of the Merger, 37,162 shares of time-vested restricted stock grants that were outstanding immediately prior to the closing of the Merger were cancelled and converted into the right to receive a lump-sum cash payment equal to $34.00 per share. The number of shares converted were calculated by multiplying the total number of shares of common stock underlying the grant by the number of months lapsed through the merger Closing Date divided by the number of months in the grant’s restricted period. Payment of the lump-sum cash awards were made in January 2017 and totaled approximately $1.3 million.

54

THE EMPIRE DISTRICT ELECTRIC COMPANY

Notes to Consolidated Financial Statements

Additionally, 42,600 shares of performance-based restricted stock granted under the 2006 SIP and the 2015 SIP that were outstanding immediately prior to the closing of the Merger were cancelled and converted into the right to receive a lump-sum cash payment. In accordance with the Merger Agreement, the performance-based restricted stock was paid equal to $34.00 per share multiplied by the total number of shares of common stock that would have been earned for performance at “target” over the performance period under the grant. Payment of these lump-sum cash awards were made in January 2017 and totaled approximately $1.4 million.

In connection with entering into the Merger Agreement, Empire has incurred approximately $9.1 million of transaction costs as of December 31, 2016. We have incurred approximately $6.9 million of additional costs subsequent to December 31, 2016 related to legal fees and final investment banker fees. We expect to incur additional transaction costs through 2017 as part of the merger, and do not expect regulatory recovery of these costs in any jurisdiction that we serve.

The Board of Directors adopted a Change In Control Severance Pay Plan ("Severance Plan") in 1991, amended most recently in 2008, that covers the Company’s executive officers as well as other key employees who are not executive officers. The Severance Plan provides severance payments and other benefits upon involuntary or voluntary termination of employment after a change in control. The completion of the Merger on January 1, 2017 triggered certain aspects of the Severance Plan and certain officers have elected voluntary termination in accordance with the Severance Plan. The Company has recorded approximately $32.7 million of Severance Plan related expenses subsequent to year end based on officer terminations. Payment of these Severance Plan expenses will occur over several years, in accordance with the schedules determined for each officer receiving the benefits.

We have evaluated subsequent events through February 15, 2017, the date the financial statements were available to be issued.

55

SCHEDULE B

FOREWORD

UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS

The accompanying unaudited pro forma consolidated financial statements give effect to the acquisition (the “Acquisition”) by Algonquin Power and Utilities Corp. (“APUC” or the “Company”) of Empire District Electric Company and its subsidiaries (collectively “Empire”) under the acquisition method of accounting. The unaudited pro forma consolidated balance sheet gives effect to the Acquisition as if it had closed on December 31, 2016. The unaudited pro forma consolidated statement of operations for the year ended December 31, 2016 give effect to the Acquisition as if it had closed on January 1, 2016.

The unaudited pro forma consolidated financial statements are presented for illustrative purposes only. The pro forma adjustments are based upon available information and certain assumptions that we believe are reasonable in the circumstances, as described in the notes to the unaudited pro forma consolidated financial statements.

Empire is a regulated utility engaged, through its subsidiaries, in electric generation, transmission and distribution and natural gas distribution. The unaudited pro forma consolidated financial statements are based on Empire’s historical consolidated financial statements as at and for the year ended December 31, 2016.  For more information regarding the foreign exchange translation from U.S. Dollars to Canadian Dollars for Empire's financial statements see "Notes to the Unaudited Pro forma Consolidated Financial Statements-Note 3(i): Foreign Exchange Translation."

The pro forma information presented, including allocation of purchase price, is based on preliminary estimates of fair values of assets acquired and liabilities assumed, available information and assumptions and may be revised as additional information becomes available. The actual adjustments to the consolidated financial statements upon the closing of the Acquisition will depend on a number of factors, including additional information available and the net assets of Empire on the closing date of the Acquisition. Therefore, the actual adjustments will differ from the pro forma adjustments, and the differences may be material. For example, the final purchase price allocation is dependent on, among other things, the finalization of asset and liability valuations. This final valuation will be based on the actual net tangible and intangible assets and liabilities of Empire that exist as of the closing date of the Acquisition. Any final adjustment may change the allocation of purchase price, which could affect the fair value assigned to the assets and  liabilities and could result in a change to the unaudited pro forma consolidated financial statements, including a change to goodwill.

Algonquin Power & Utilities Corp

Unaudited Pro Forma Consolidated Balance Sheet

December 31, 2016

(in millions of Canadian dollars)

	APUC			Empire 3(i)		Pro Forma Adjustments					Pro forma Consolidated
Assets
Currents assets:
Cash and cash equivalents	$	110		$	2	$	(12	)	3(b	)	$	47
							1150		3(c	)
							(48	)	3(c	)
							(9	)	3(c	)
							(383	)	3(c	)
							25		3(c	)
							1064		3(d	)
							(6	)	3(d	)
							(1794	)	3(d	)
							(52	)	3(e	)
Accounts receivable, net		190			98							288
Fuel and natural gas in storage		22			34							56
Regulatory assets		48			11							59
Prepaid expenses		26			13							39
Deferred income taxes							13		3(c	)		20
							2		3(c	)
							5		3(c	)
Derivative instruments		77			8		(18	)	3(c	)		67
Other assets		19			47							66
		492			213		(63	)				642
Property, plant and equipment, net		4890			2747							7637
Intangible assets, net		65										65
Goodwill		307			53		(53	)	3(b	)		1270
							963		3(b	)
Regulatory assets		243			285							528
Derivative instruments		75			1							76
Long-term investments		105										105
Deferred income taxes		30										30
Restricted cash		2026					(2008	)	3(b	)		18
Other assets		16			4							20
Total assets	$	8249		$	3303	$	(1161	)			$	10391
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable		90			45							135
Accrued liabilities		308			41							349
Dividends payable		39			5							44
Regulatory liabilities		48			19							67
Long-term debt		10			34							44
Other long-term liabilities and deferred credits		43										43
Other liabilities		8			21							29
Derivative instruments					2							2
		546			167							713
Long-term debt		3903			1114		1064		3(d	)		4281
							(6	)	3(d	)
							(1794	)	3(d	)
Convertible Debentures		359					(383	)	3(c	)
							25		3(c	)
							(1	)	3(c	)
Regulatory liabilities		135			183							318
Deferred income taxes		288			577							865
Derivative instruments		105			2							107
Pension and other post-employment benefits obligation		148			105							253
Other long-term liabilities		232			45							277
Preferred shares, Series C		18										18
		5188			2026		(1095	)				6119
Redeemable non-controlling interest		29										29
Equity:
Preferred shares		214										214
Common shares		1972			59		(59	)	3(g	)		3087
							1150		3(c	)
							(35	)	3(c	)
Additional paid-in capital		39			896		(896	)	3(g	)		39
Deficit		(556	)		155		(155	)	3(g	)		(627	)
							(52	)	3(e	)
							(7	)	3(c	)
							1		3(c	)
							(13	)	3(c	)
Accumulated other comprehensive income		255										255
		1924			1110		(66	)				2968
Non-controlling interest		562										562
Total equity		2486			1110		(66	)				3530
Total liabilities and equity	$	8249		$	3303	$	(1161	)			$	10391

See accompanying notes to unaudited pro forma consolidated financial statements

Algonquin Power & Utilities Corp

Unaudited Pro Forma Consolidated Statement of Operations

Year ended December 31, 2016

(in millions of Canadian dollars, except share and per share amounts)

	APUC			Empire 3(i)		Pro Forma Adjustments					Pro Forma Consolidated
Revenue
Regulated electricity distribution		228		$	751						$	979
Regulated gas distribution		406			49							455
Regulated water reclamation and distribution		182			3							185
Non-regulated energy sales		243										243
Other revenue		37			9							47
		1096			812		.					1908
Expenses
Operating expenses		333			179							512
Regulated electricity purchased		120			205							325
Regulated gas purchased		142			20							162
Regulated water purchased		12										12
Non-regulated energy purchased		21										21
Administrative expenses		46			88							134
Depreciation and amortization		187			114							301
		861			606							1467
Operating income		235			206							441
Interest expense on convertible debentures and acquisition financing		58					(49	)	3(c	)
							(9	)	3(d	)
Interest expense on long-term debt and others		74			57		37		3(d	)		168
Interest, dividend, equity and other income		(11	)									(11	)
Other gains		(9	)									(9	)
Acquisition-related costs		12			12		(15	)	3(e	)		9
Gain on long-lived assets, net		(3	)									(3	)
Gain on derivative financial instruments		(16	)				18		3(c	)		2
		105			69		(18	)				156
Earnings before income taxes		130			137		18					285
Income tax expense (recovery)		37			52		(3	)				86
Net earnings		92			85		21					199
Net effect of non-controlling interests		(39	)									(39	)
Net earnings attributable to Algonquin Power & Utilities Corp.	$	131		$	85	$	21				$	237
Weighted average shares of common stock outstanding (in millions)
Basic		272					108		3(h	)		380
Diluted		274					108		3(h	)		383
Basic net earnings per share	$	0.44									$	0.60
Diluted net earnings per share	$	0.44									$	0.59

See accompanying notes to unaudited pro forma consolidated financial statements

Algonquin Power & Utilities Corp.

Notes to the unaudited pro forma consolidated financial statements

As of and for the year ended December 31, 2016

(in Canadian dollars, unless otherwise stated)

1. BASIS OF PRESENTATION

The accompanying unaudited pro forma consolidated financial statements give effect to the acquisition (the “Acquisition”) by Algonquin Power and Utilities Corp. (“APUC” or the “Company”) of the Empire District Electric Company and its subsidiaries (collectively, “Empire”) on January 1, 2017. The accompanying unaudited pro forma consolidated financial statements have been prepared by management of APUC and are derived from the audited consolidated financial statements of APUC as of and for the year ended December 31, 2016 and the audited consolidated financial statements of Empire as of and for the year ended December 31, 2016.

The accompanying unaudited pro forma consolidated financial statements utilize accounting policies that are consistent with those disclosed in the Company’s and Empire’s audited consolidated financial statements as of December 31, 2016 and were prepared in accordance with accounting principles generally accepted in the United States.

The accompanying unaudited pro forma consolidated balance sheet and unaudited pro forma consolidated statement of operations reflect the Acquisition as if it had closed on December 31, 2016 and January 1, 2016, respectively. The accompanying unaudited pro forma consolidated financial statements may not be indicative of the results that would have been achieved if the transactions reflected therein had been completed on the dates indicated or the results which may be obtained in the future. For instance, the actual purchase price allocation will reflect the fair value, at the purchase date, of the assets acquired and liabilities assumed based upon the Company’s evaluation of such assets and liabilities following the closing of the Acquisition and, accordingly, the final purchase price allocation, as it relates principally to regulatory assets and liabilities, long-term debt, assets of unregulated operations and goodwill, may differ materially from the preliminary allocation reflected herein.

The accompanying unaudited pro forma consolidated financial statements should be read in conjunction with; the audited consolidated financial statements of Empire and APUC, including the notes thereto.

Certain amounts in the historical financial statements of Empire have been reclassified in the unaudited pro forma consolidated balance sheet and statements of operations to reflect the presentation classifications in APUC’s consolidated financial statements.

The underlying assumptions for the pro forma adjustments provide a reasonable basis for presenting the significant financial effect directly attributable to the Acquisition. These pro forma adjustments are tentative and are based on currently available financial information and certain estimates and assumptions. The actual adjustments to the consolidated financial statements will depend on a number of factors. Therefore, it is expected that the actual adjustments will differ from the pro forma adjustments, and the differences may be material.

2. DESCRIPTION OF TRANSACTION

Pursuant to an agreement and plan of a merger between Liberty Energy Utilities Co. (“Liberty Energy”), a direct wholly-owned subsidiary of APUC, and Empire, the Company indirectly purchased all of the outstanding common shares of Empire for U.S. $34.00 per share. The purchase price for the equity of Empire was U.S. $1.5 billion ($2 billion (Note 3(a)). The Company assumed Empire’s consolidated debt, which carrying value was U.S. $855 million as at December 31, 2016.

The Company had arranged a committed debt Acquisition Facility for U.S. $1.3 billion repayable in full on the first anniversary following its advance which together with existing cash and other sources available to APUC, an existing revolver and the initial instalment received on the convertible unsecured subordinated debentures (“the Debentures”) fully funded the purchase price.

Algonquin Power & Utilities Corp.

Notes to the unaudited pro forma consolidated financial statements

As of and for the year ended December 31, 2016

(in Canadian dollars, unless otherwise stated)

2. DESCRIPTION OF TRANSACTION (continued)

The accompanying unaudited pro forma consolidated financial statements assume that at closing, the Acquisition was financed through the net proceeds from the $1.15 billion common equity issuance (as further described below in note 3(c)), with the balance funded through the issuance of unsecured senior notes and existing credit facility, as described further in note 3(d) below.

The accompanying unaudited pro forma consolidated financial statements assume that the Debentures were issued and immediately fully converted into APUC common shares at the assumed closing date of the Acquisition and that the Senior Unsecured Notes were issued at that same date. Therefore, the accompanying unaudited pro forma consolidated statements of operations do not recognize interest costs associated with the Debentures or the Acquisition Facility. Interest costs associated with the Debentures were funded through operating cash flows and the revolving credit facility.

3. PRO FORMA ASSUMPTIONS AND ADJUSTMENTS

(a) Purchase Price and Financing Structure

The following is the purchase price, estimated net funding requirements and financing structure for the Acquisition. These estimates have been reflected in the accompanying unaudited pro forma consolidated financial statements.

Net Purchase Price	Cdn $millions
Purchase price, before assumed debt	$	3,168
Assumed debt of Empire		(1,148	)
Purchase price	$	2,020
Estimated Net Funding Requirements
Purchase price	$	2,020
Assumed debt of Empire		1,148
Common share issuance costs (note 3(c))		48
Acquisition facility costs (note 3(d))		16
Estimated acquisition costs (note 3(e))		67
Estimated debt issuance costs (note 3(d))		6
Interest on Debentures (note 3(c))		58
Estimated net funding requirements	$	3,362
Assumed Financing Structure
Assumed debt of Empire	$	1,148
Common share issuance (note 3(c))		1,150
Senior Unsecured Notes, Credit Facility (note 3(d))		1,064
	$	3,362

Algonquin Power & Utilities Corp.

Notes to the unaudited pro forma consolidated financial statements

As of and for the year ended December 31, 2016

(in Canadian dollars, unless otherwise stated)

(b) Allocation of purchase price

Based in Joplin, Missouri, Empire is an investor-owned, regulated utility providing electric, natural gas (through its wholly-owned subsidiary The Empire District Gas Company) and water service in Missouri, Kansas, Oklahoma and Arkansas. As part of Empire’s electric segment, they also provide water service to three towns in Missouri. The Empire District Gas Company, a wholly owned subsidiary of Empire, engages in the distribution of natural gas in Missouri. The determination of earnings is based on regulated rates of return that are applied to rate bases and does not change with a change of ownership. “Rate bases” includes jurisdictional rate base, in some cases assets earning a return through clauses and riders.

The excess of the purchase price of the Acquisition, before assumed debt and acquisition costs, over the assumed fair value of net assets acquired from Empire is classified as goodwill on the accompanying unaudited pro forma consolidated balance sheet.

The unaudited pro forma consolidated balance sheet presents the payment of the purchase price of       $2,020 million as a draw of $2,008 million (U.S. $1,496 million) from restricted cash for funds that had been transferred to the paying agent and the remaining $12 million using cash. The purchase price has been allocated to the estimated fair values of Empire net assets and liabilities as at December 31, 2016 in accordance with the acquisition method, as follows:

	Dec-16
Cdn $millions	Empire		Estimated Fair Valueand other adjustments			Net Total
Assets acquired
Cash and cash equivalents	$	2				$	2
Accounts receivable, net		98					98
Fuel and natural gas in storage		34					34
Regulatory assets		11					11
Prepaid expenses		13					13
Derivative instruments		8					8
Other current assets		47					47
Total current assets		213					213
Property, plant and equipment, net		2747					2747
Derivative instruments		1					1
Regulatory assets		285					285
Goodwill		53		(53	)
Other		4					4
Total assets	$	3303	$	(53	)	$	3250
Liabilities assumed
Accounts payable	$	45				$	45
Accrued liabilities		41					41
Regulatory liabilities		19					19
Dividends payable		5					5
Long-term debt		34					34
Other liabilities		21					21
Derivative instruments		2					2
		167					167
Long-term debt		1114					1114
Regulatory liabilities		183					183
Deferred income taxes		577					577
Derivative instruments		2					2
Pension and other post-employment benefits obligation		105					105
Other long-term liabilities		45					45
Total Liabilities	$	2193				$	2193
Net assets as at December 31, 2016	$	1110				$	1057
Purchase price, before assumed debt and acquisition costs							2020
Goodwill						$	963

Algonquin Power & Utilities Corp.

Notes to the unaudited pro forma consolidated financial statements

As of and for the year ended December 31, 2016

(in Canadian dollars, unless otherwise stated)

(c) Common Share Issuance

In 2016, to finance a portion of the Acquisition, APUC completed the sale of $1.15 billion principal amount of 5% Debentures. These Debentures were sold on an instalment basis, with $383 million paid on closing of the offering, and the remaining paid on February 2, 2017, following satisfaction of conditions precedent to the closing of the Acquisition. For the purposes of these unaudited pro forma consolidated financial statements, the remaining $767 million relating to the final instalment are assumed to have been received and the aggregate amount of $1.15 billion of Debentures to have been fully converted at $10.60 per share to approximately 108.5 million common shares on December 31, 2016.

Underwriting and issuance costs of $25 million incurred in 2016 were netted against the proceeds from the first instalment of the Debentures as at December 31, 2016.  For purposes of the unaudited pro forma financial statements, these costs were reversed and the total estimated underwriting and issuance costs of $48 million or $35 million net of deferred income tax asset of $13 million were recorded as a deduction from the carrying amount of the equity issued.

Interest costs and amortization of issuance fees of $49 million incurred in 2016 together with corresponding tax recovery of $13 million were expensed in the statement of operations of APUC for the year ended December 31, 2016. Interest costs associated with the Debentures at 5% are expected at a minimum to be $58 million for a 12 month period prior to closing and will result in a corresponding deferred income tax asset of approximately $15 million. As the unaudited pro forma consolidated financial statements assume that the Debentures will be issued and immediately fully converted into APUC common shares at the assumed closing date of the Acquisition, the difference in interest costs of $9 million with corresponding tax recovery of $2 million is reflected as an increase to deficit on the unaudited pro forma consolidated balance sheet. However, the costs incurred to-date have been removed from interest expense on convertible debentures and acquisition financing in the unaudited pro forma statement of operations for year ended December 31, 2016 on the basis that these expenses are directly incremental to the Acquisition of Empire and are non-recurring in nature

Mark-to-market gains of $18 million, and corresponding tax expense of $5 million, from foreign exchange forwards contracts, which are economically hedging the proceeds of the final instalment of the Debentures, have been removed from loss (gain) on derivative financial instruments in the unaudited pro forma statement of operations for the year ended December 31, 2016 on the basis that these expenses are directly incremental to the Acquisition of Empire and are non-recurring in nature

(d) Senior Unsecured Notes, Credit Facility, and Acquisition Facility

The Company will raise approximately $1.064 billion for purposes of financing a portion of the Acquisition through the issuance of senior unsecured notes, and drawing on existing credit facilities.

On March 1, 2017, the Company entered into an agreement to issue U.S. $750 million senior unsecured notes, of which U.S. $650 million is to be used for purposes of financing a portion of the Acquisition. The notes have an average life of approximately 15 years and a weighted average coupon of 4.0% or 3.6% after considering the effects of interest rate hedges entered into in 2016. The remaining $191.5 million is financed using existing credit facilities with effective interest rates of 3.15%.

These transactions would result in incremental interest expense of $37 million, corresponding deferred income tax benefits of $14 million for the year ended December 31, 2016.

Estimated issuance costs for the Senior Unsecured Notes of approximately $6 million have been netted against the proceeds from issuances, and amortized over the weighted average term of fifteen years.

The repayment of the Acquisition facility of $1,794 million (U.S. $1,336 million) with the permanent financing described above is assumed to occur on December 31, 2016 on the unaudited pro forma consolidated balance sheet.  Acquisition facility related costs of $16 million were incurred in 2016. Amortization of $9 million recorded in 2016, together with deferred taxes of $3 million have been reversed from Interest expense on convertible debentures and acquisition financing on the unaudited pro forma consolidated statement of operations for the year ended December 31, 2016 on the basis that these expenses are directly incremental to the Acquisition of Empire and are non-recurring in nature.

Algonquin Power & Utilities Corp.

Notes to the unaudited pro forma consolidated financial statements

As of and for the year ended December 31, 2016

(in Canadian dollars, unless otherwise stated)

(e) Acquisition costs

Acquisition costs are estimated at approximately $67 million of which $15 million was incurred in 2016. Acquisition costs are composed of estimated investment banking, accounting, tax, legal and other costs associated with the completion of the Acquisition. These costs have been included as a pro forma adjustment to deficit on the unaudited pro forma consolidated balance sheet. Costs incurred to-date of $15 million have been reversed from acquisition-related costs in the unaudited pro forma consolidated statement of operations for the year ended December 31, 2016 on the basis that these expenses are directly incremental to the Acquisition of Empire and are non-recurring in nature.

(f) Income taxes

Income taxes applicable to the pro forma adjustments are calculated at APUC’s statutory tax rates of 26.50% (for items with tax effect in the Canadian entities) and 38% (for items in the US entities).

The deferred income tax asset and liability is the cumulative amount of tax applicable to temporary differences between the accounting and tax values of assets and liabilities. Deferred income tax assets and liabilities are measured at enacted tax rates expected to apply when these differences are expected to reverse.

(g) Empire historical shareholders’ equity

The historical shareholders’ equity of Empire, which includes common shares, additional paid-in capital and retained earnings, has been eliminated in the unaudited pro forma consolidated balance sheet.

(h) Earnings per common share

The calculation of the pro forma earnings per common share for the year ended December 31, 2016 reflects the issuance of approximately 108.5 million APUC common shares upon the conversion of the Debentures which is assumed to take place on closing of the Acquisition, as if the issuance had taken place on January 1, 2016.

(i) Foreign exchange translation

The assets and liabilities of Empire, which has a US dollar functional currency, are translated to APUC’s Canadian dollar reporting currency at the exchange rate in effect as at December 31, 2016. Revenues and expenses of Empire’s operations are translated at the average exchange rate in effect during the respective reporting periods. The following exchange rates were utilized for the unaudited pro forma consolidated financial statements:

Balance Sheet (US$ to Cdn$)
Spot rate December 31, 2016	1.3427
Statement of Operations (US$ to Cdn$)
Average rate year ended December 31, 2016	1.3245