Algonquin Power & Utilities (AQN) 40-F 2015 FY Annual report (Canada)

Consolidated Financial Statements of

Algonquin Power & Utilities Corp.

For the years ended December 31, 2015 and 2014

MANAGEMENT’S REPORT

Financial Reporting

The preparation and presentation of the accompanying Consolidated Financial Statements, MD&A and all financial information in the Financial Statements are the responsibility of management and have been approved by the Board of Directors. The Financial Statements have been prepared in accordance with U.S. generally accepted accounting principles. Financial statements, by nature include amounts based upon estimates and judgments. When alternative accounting methods exist, management has chosen those it deems most appropriate in the circumstances. Management has prepared the financial information presented elsewhere in this document and has ensured that it is consistent with that in the consolidated financial statements.

The Board of Directors and its committees are responsible for all aspects related to governance of the Company. The Audit Committee of the Board of Directors, composed of directors who are unrelated and independent, has a specific responsibility to oversee management’s efforts to fulfill its responsibilities for financial reporting and internal controls related thereto. The Committee meets with management and independent auditors to review the consolidated financial statements and the internal controls as they relate to financial reporting. The Audit Committee reports its findings to the Board of Directors for its consideration in approving the consolidated financial statements for issuance to the shareholders.

Internal Control over Financial Reporting

Management is also responsible for establishing and maintaining adequate internal control over financial reporting. The Company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

Management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2015, based on the framework established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this assessment, management concluded that the Company maintained effective internal control over financial reporting as of December 31, 2015.

March 10, 2016

/s/ Ian Robertson	/s/ David Bronicheski
Chief Executive Officer	Chief Financial Officer

INDEPENDENT AUDITORS’ REPORT OF REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of Algonquin Power & Utilities Corp.

We have audited the accompanying consolidated financial statements of Algonquin Power & Utilities Corp., which comprise the consolidated balance sheets as at December 31, 2015 and 2014 and the consolidated statements of operations, comprehensive income, equity, and cash flows for each of the years in the two-year period ended December 31, 2015, and a summary of significant accounting policies and other explanatory information.

Management’s Responsibility for the Consolidated Financial Statements

Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with U.S. generally accepted accounting principles, and for such internal control as management determines is necessary to enable the preparation 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 these consolidated financial statements based on our audits. We conducted our audits in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we comply with ethical requirements and 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 the auditors’ 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, the auditors consider internal control relevant to the entity’s preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated financial statements, evaluating the appropriateness of accounting policies used and the reasonableness of 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 in our audit is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the consolidated financial statements present fairly, in all material respects, the consolidated financial position of Algonquin Power & Utilities Corp. as at December 31, 2015 and 2014, and the consolidated results of its operations and its cash flows for each of the years in the two-year period ended December 31, 2015, in conformity with U.S. generally accepted accounting principles.

Other Matter

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Algonquin Power & Utilities Corp.’s internal control over financial reporting as of December 31, 2015, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated March 10, 2016 expressed an unqualified opinion on Algonquin Power & Utilities Corp.’s internal control over financial reporting.

/s/ Ernst & Young LLP        

Chartered Professional Accountants,

Licensed Public Accountants

Toronto, Canada

March 10, 2016

INDEPENDENT AUDITORS’ REPORT ON INTERNAL CONTROLS UNDER STANDARDS OF THE PUBLIC COMPANY ACCOUNTING OVERSIGHT BOARD (UNITED STATES)

To the Board of Directors and Shareholders of Algonquin Power & Utilities Corp.

We have audited Algonquin Power & Utilities Corp.’s internal control over financial reporting as of December 31, 2015, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). Algonquin Power & Utilities Corp.’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on Algonquin Power & Utilities Corp.’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, Algonquin Power & Utilities Corp. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2015, based on the COSO criteria.

We also have audited, in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Algonquin Power & Utilities Corp. as of December 31, 2015 and 2014, and the related consolidated statements of operations, comprehensive income, equity, and cash flows for each of the years in the two-year period ended December 31, 2015 and our report dated March 10, 2016 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP        

Chartered Professional Accountants,

Licensed Public Accountants

Toronto, Canada

March 10, 2016

Algonquin Power & Utilities Corp.

Consolidated Balance Sheets

(thousands of Canadian dollars)
	December 31, 2015		December 31, 2014
ASSETS
Current assets:
Cash and cash equivalents	$	124,353	$	9,273
Accounts receivable, net (note 4)	186,681		188,573
Natural gas in storage (note 1(h))	28,502		31,550
Regulatory assets (note 7)	32,213		61,645
Prepaid expenses	18,409		10,431
Derivative instruments (note 24)	15,039		10,688
Other current assets	18,537		15,359
	423,734		327,519
Property, plant and equipment, net (note 5)	3,873,684		3,278,422
Intangible assets, net (note 6)	77,963		54,011
Goodwill (note 6)	110,493		92,328
Regulatory assets (note 7)	213,102		185,627
Derivative instruments (note 24)	73,322		31,782
Long-term investments (note 8)	174,802		43,279
Deferred income taxes (note 19)	18,109		64,275
Other assets (note 12)	26,516		25,605
	$	4,991,725	$	4,102,848

Algonquin Power & Utilities Corp.

Consolidated Balance Sheets

(thousands of Canadian dollars)
	December 31, 2015			December 31, 2014
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	50,428		$	68,540
Accrued liabilities	193,320			199,374
Dividends payable (note 16)	41,802			25,395
Regulatory liabilities (note 7)	44,167			20,590
Long-term debt (note 9)	8,945			9,130
Other long-term liabilities and deferred credits (note 13)	36,621			49,303
Other liabilities	16,593			10,234
	391,876			382,566
Long-term debt (note 9)	1,477,850			1,262,589
Regulatory liabilities (note 7)	131,180			101,166
Deferred income taxes (note 19)	175,799			134,460
Derivative instruments (note 24)	106,628			40,088
Pension and other post-employment benefits (note 10)	150,094			138,602
Other long-term liabilities (note 13)	223,135			177,235
Preferred shares, Series C (note 11)	17,548			17,608
	2,282,234			1,871,748
Redeemable non-controlling interest (note 3(e))	25,751			12,146
Equity:
Preferred shares (note 14(b))	213,805			213,805
Common shares (note 14(a))	1,808,894			1,633,262
Subscription receipts (note 14(a)(ii))	110,503			110,503
Additional paid-in capital	38,241			33,068
Deficit	(523,116		)	(505,305		)
Accumulated other comprehensive income (note 15)	286,737			34,213
Total Equity attributable to shareholders of Algonquin Power & Utilities Corp.	1,935,064			1,519,546
Non-controlling interests	356,800			316,842
Total Equity	2,291,864			1,836,388
Commitments and contingencies (note 22)
Subsequent events (notes 3(a) and (b), 8(e), 9, 14(a)(iii) and 25)
	$	4,991,725		$	4,102,848

See accompanying notes to consolidated financial statements

Algonquin Power & Utilities Corp.

Consolidated Statements of Operations

(thousands of Canadian dollars, except per share amounts)	Year ended December 31
	2015			2014
Revenue
Regulated electricity distribution	$	224,110		$	204,721
Regulated gas distribution	464,767			446,025
Regulated water reclamation and distribution	78,467			66,419
Non-regulated energy sales	222,581			202,300
Other revenue	37,930			22,149
	1,027,855			941,614
Expenses
Operating expenses	278,561			234,038
Regulated electricity purchased	131,647			120,506
Regulated gas purchased	217,236			261,116
Non-regulated energy purchased	27,990			39,264
Administrative expenses	40,675			34,692
Depreciation and amortization	149,806			114,047
Gain on foreign exchange	(2,631		)	(1,112		)
	843,284			802,551
Operating income from continuing operations	184,571			139,063
Interest expense	65,993			62,418
Interest, dividend, equity and other income	(9,095		)	(7,758		)
Other gains	(5,110		)	—
Acquisition-related costs	1,832			2,552
Write-down of long-lived assets and loss on disposal	2,890			8,027
Loss (gain) on derivative financial instruments (note 24(b)(iv))	(2,188		)	1,375
	54,322			66,614
Earnings from continuing operations before income taxes	130,249			72,449
Income tax expense (note 19)
Current	7,310			3,674
Deferred	36,403			13,133
	43,713			16,807
Earnings from continuing operations	86,536			55,642
Loss from discontinued operations, net of tax	(1,032		)	(2,127		)
Net earnings	85,504			53,515
Net loss attributable to non-controlling interests (note 18)	(31,976		)	(22,186		)
Net earnings attributable to shareholders of Algonquin Power & Utilities Corp.	$	117,480		$	75,701
Series A and D Preferred shares dividend (note 16)	10,400			9,503
Net earnings attributable to common shareholders of Algonquin Power & Utilities Corp.	$	107,080		$	66,198
Basic net earnings per share from continuing operations (note 20)	$	0.43		$	0.32
Basic net earnings per share (note 20)	0.42			0.31
Diluted net earnings per share from continuing operations (note 20)	0.42			0.32
Diluted net earnings per share (note 20)	$	0.42		$	0.31

See accompanying notes to consolidated financial statements

Algonquin Power & Utilities Corp.

Consolidated Statements of Comprehensive Income

(thousands of Canadian dollars)	Year ended December 31
	2015			2014
Net earnings	$	85,504		$	53,515
Other comprehensive income:
Foreign currency translation adjustment, net of tax recovery of $nil and $1,049, respectively (notes 1(v), 24(b)(iii) and 24(c))	289,035			104,183
Change in fair value of cash flow hedges’, net of tax expense of $12,010 and $6,589, respectively (note 24(b)(ii))	16,165			2,799
Change in unrealized appreciation in value of available-for-sale investments	(73		)	1
Change in pension and other post-employment benefits, net of tax expense of $4,923 and tax recovery of $22,446, respectively (note 10)	7,571			(35,669		)
Other comprehensive income, net of tax	312,698			71,314
Comprehensive income	398,202			124,829
Comprehensive income attributable to the non-controlling interests	28,198			7,077
Comprehensive income attributable to shareholders of Algonquin Power & Utilities Corp.	$	370,004		$	117,752

See accompanying notes to consolidated financial statements

Algonquin Power & Utilities Corp.

Consolidated Statement of Equity

(thousands of Canadian dollars) For the year ended December 31, 2015
	Algonquin Power & Utilities Corp. Shareholders
	Common shares		Preferred shares		Subscription receipts		Additional paid-in capital			Accumulated deficit			Accumulated OCI		Non- controlling interests			Total
Balance, December 31, 2014	$	1,633,262	$	213,805	$	110,503	$	33,068		$	(505,305	)	$	34,213	$	316,842		$	1,836,388
Net earnings (loss)	—		—		—		—			117,480			—		(31,976		)	85,504
Redeemable non-controlling interests not included in equity	—		—		—		—			—			—		3,571			3,571
Other comprehensive income	—		—		—		—			—			252,524		60,174			312,698
Dividends declared and distributions to non-controlling interests	—		—		—		—			(105,929		)	—		(2,626		)	(108,555		)
Dividends and issuance of shares under dividend reinvestment plan	29,302		—		—		—			(29,302		)	—		—			—
Contributions received from non-controlling interests	—		—		—		—			—			—		10,815			10,815
Shares issued pursuant to public offering, net of costs (note 14(a)(i))	144,987		—		—		—			—			—		—			144,987
Issuance of common shares under employee share purchase plan	1,343		—		—		(282		)	(60		)	—		—			1,001
Share-based compensation	—		—		—		5,455			—			—		—			5,455
Balance, December 31, 2015	$	1,808,894	$	213,805	$	110,503	$	38,241		$	(523,116	)	$	286,737	$	356,800		$	2,291,864

Algonquin Power & Utilities Corp.

Consolidated Statement of Equity

(thousands of Canadian dollars) For the year ended December 31, 2014
	Algonquin Power & Utilities Corp. Shareholders
	Common shares		Preferred shares		Subscription receipts		Additional paid-in capital		Accumulated deficit			Accumulated OCI			Non- controlling interests			Total
Balance, December 31, 2013	$	1,351,264	$	116,546	$	—	$	7,313	$	(488,406	)	$	(31,410	)	$	510,654		$	1,465,961
Net earnings (loss)	—		—		—		—		75,701			—			(22,186		)	53,515
Redeemable non-controlling interests not included in equity	—		—		—		—		—			—			(289		)	(289		)
Other comprehensive income	—		—		—		—		—			42,051			29,263			71,314
Dividends declared and distributions to non-controlling interests	—		—		—		—		(75,205		)	—			(4,738		)	(79,943		)
Dividends and issuance of shares under dividend reinvestment plan	17,395		—		—		—		(17,395		)	—			—			—
Contributions received from non-controlling interests	—		—		—		—		—			—			9,934			9,934
Issuance of subscription receipts (note 14(a)(ii))	—		—		110,503		—		—			—			—			110,503
Shares issued pursuant to public offering, net of costs (note 14(a)(i))	263,869		—		—		—		—			—			—			263,869
Issuance of common shares under employee share purchase plan	734		—		—		—		—			—			—			734
Share-based compensation expense	—		—		—		3,203		—			—			—			3,203
Preferred shares, Series D (note 14(b))	—		97,259		—		—		—			—			—			97,259
Acquisition of non-controlling interest (note 18)	—		—		—		22,552		—			23,572			(205,796		)	(159,672		)
Balance, December 31, 2014	$	1,633,262	$	213,805	$	110,503	$	33,068	$	(505,305	)	$	34,213		$	316,842		$	1,836,388

See accompanying notes to consolidated financial statements

Algonquin Power & Utilities Corp.

Consolidated Statements of Cash Flows

(thousands of Canadian dollars)	Year ended December 31
	2015			2014
Cash provided by (used in):
Operating Activities
Net earnings from continuing operations	$	86,536		$	55,642
Adjustments and items not affecting cash:
Depreciation and amortization	151,627			115,399
Deferred taxes	36,403			13,133
Unrealized loss (gain) on derivative financial instruments	(1,990		)	3,046
Share-based compensation expense	5,455			3,203
Cost of equity funds used for construction purposes	(2,424		)	(1,910		)
Pension and post-employment expense	(3,333		)	(2,050		)
Write-down of long-lived assets	1,781			8,463
Unrealized gain on disposal of VIE	220			—
Increase in deferred income	550			—
Changes in non-cash operating items (note 23)	(11,149		)	(1,790		)
Changes in non-cash operating items from discontinued operations	—			1,262
Cash used in discontinued operations	(1,806		)	(1,682		)
	261,870			192,716
Financing Activities
Cash dividends on common shares	(79,121		)	(57,848		)
Cash dividends on preferred shares	(10,400		)	(9,503		)
Cash contributions from non-controlling interests	15,222			11,845
Production-based cash contributions from non-controlling interest	10,815			8,976
Cash distributions to non-controlling interests	(2,936		)	(4,738		)
Issuance of common shares, net of costs	144,694			261,452
Proceeds from subscription receipts	—			110,503
Issuance of preferred shares, net of costs	—			96,271
Acquisition of non-controlling interest	—			(127,121		)
Increase in long-term debt	248,811			236,528
Decrease in long-term debt	(196,149		)	(286,552		)
Increase in other long-term liabilities	31,544			18,618
Decrease in other long-term liabilities	(6,182		)	(3,091		)
	156,298			255,340
Investing Activities
Increase (decrease) in other assets	281			(13,785		)
Distributions received in excess of equity income	1,386			264
Receipt of principal on notes receivable	29,273			280
Additions to property, plant and equipment	(204,195		)	(432,373		)
Acquisitions of long-term investments	(138,560		)	(25,432		)
Acquisitions of operating entities	(3,717		)	(8,757		)
Proceeds from sale of long-lived assets	5,516			26,535
	(310,016		)	(453,268		)
Effect of exchange rate differences on cash	6,928			646
Increase (decrease) in cash and cash equivalents	115,080			(4,566		)
Cash and cash equivalents, beginning of year	9,273			13,839
Cash and cash equivalents, end of year	$	124,353		$	9,273
Supplemental disclosure of cash flow information:	2015			2014
Cash paid during the year for interest expense	$	69,610		$	57,098
Cash paid during the year for income taxes	$	6,153		$	2,571
Non-cash financing and investing activities:
Property, plant and equipment acquisitions in accruals	$	44,834		$	25,568
Issuance of common shares under dividend reinvestment plan and share-based compensation plans	$	30,645		$	18,129

See accompanying notes to consolidated financial statements

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2015 and 2014

(in thousands of Canadian dollars, except as noted and per share amounts)

Algonquin Power & Utilities Corp. (“APUC” or the “Company”) is an incorporated entity under the Canada Business Corporations Act. APUC is a diversified generation, transmission and distribution utility company. The distribution business group operates in the United States under the name of Liberty Utilities Co. (“Distribution Group”) and provides rate regulated water, electricity and natural gas utility services. The generation business group operates under the name Algonquin Power Co. (“Generation Group”) and owns or has interests in a portfolio of non-regulated North American based contracted wind, solar, hydroelectric and natural gas powered generating facilities. The transmission business group operates under the name Liberty Utilities (Pipeline & Transmission) (“Transmission Group”) and invests in rate regulated electric transmission and natural gas pipeline systems in the United States and Canada.

1. Significant accounting policies

(a) Basis of preparation

The accompanying consolidated financial statements and notes have been prepared in accordance with generally accepted accounting principles in the United States (“U.S. GAAP”) and follow disclosure required under Regulation S-X provided by the U.S. Securities and Exchange Commission.  

(b) Basis of consolidation

The accompanying consolidated financial statements of APUC include the accounts of APUC, its wholly owned subsidiaries and variable interest entities (“VIEs”) where the Company is the primary beneficiary (note 1(l)). Intercompany transactions and balances have been eliminated. Interests in subsidiaries owned by third parties are included in non-controlling interests (note 1(q)).

(c) Business combinations, intangible assets and goodwill

The Company accounts for acquisitions of entities or assets which meet the definition of a business as business combinations. The determination of whether the definition of a business has been met for a development stage project depends on the stage of development (permitting, customer contracting, financing, construction) and the significance of the development risk with respect to achieving commercial operation. Business combinations are accounted for using the acquisition method. Assets acquired and liabilities assumed are measured at their fair value at the acquisition date. Acquisition costs are expensed in the period incurred. When the set of activities does not represent a business, the transaction is accounted for as an asset acquisition and includes acquisitions costs.

Intangible assets acquired are recognized separately at fair value if they arise from contractual or other legal rights or are separable. Power sales contracts are amortized on a straight-line basis over the remaining term of the contract ranging from 6 to 25 years from the date of acquisition. Interconnection agreements are amortized on a straight-line basis over their estimated life of 40 years. Customer relationships are amortized on a straight-line basis over their estimated life of 40 years.

Goodwill represents the excess of the purchase price of an acquired business over the fair value of the net assets acquired. Goodwill is not included in the rate-base on which regulated utilities are allowed to earn a return and is not amortized.

During the fourth quarter of each year, the Company assesses qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit to which goodwill is attributed is less than its carrying amount. If it is more likely than not that a reporting unit’s fair value is less than its carrying amount or if a quantitative assessment is elected, the Company calculates the fair value of the reporting unit. The carrying amount of the reporting unit’s goodwill is considered not recoverable if the carrying amount of the reporting unit as a whole exceeds the reporting unit’s fair value. An impairment charge is recorded for any excess of the carrying value of the goodwill over the implied fair value. Goodwill is tested for impairment between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount.

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2015 and 2014

(in thousands of Canadian dollars, except as noted and per share amounts)

1. Significant accounting policies (continued)

(d) Accounting for rate regulated operations

The regulated utility operating companies owned by the Company are subject to rate regulation generally overseen by the public utility commission of the states in which they operate (the “Regulator”). The Regulator provides the final determination of the rates charged to customers. APUC’s regulated utility operating companies are accounted for under the principles of U.S. Financial Accounting Standards Board (“FASB”)ASC Topic 980, Regulated Operations (“ASC 980”). Under ASC 980, regulatory assets and liabilities are recorded to the extent that they represent probable future revenue or expenses associated with certain charges or credits that will be recovered from or refunded to customers through the rate making process. Included in note 7 “Regulatory matters” are details of regulatory assets and liabilities, and their current regulatory treatment.

In the event the Company determines that its net regulatory assets are not probable of recovery, it would no longer apply the principles of the current accounting guidance for rate regulated enterprises and would be required to record an after-tax, non-cash charge or credit against earnings for any remaining regulatory assets (liabilities). The impact could be material to the Company’s reported financial condition and results of operations.

The electric, gas and water utilities’ accounts are maintained in accordance with the Uniform System of Accounts prescribed by the Federal Energy Regulatory Commission (“FERC”) and National Association of Regulatory Utility Commissioners. 

(e) Cash and cash equivalents

Cash and cash equivalents include all highly liquid instruments with an original maturity of three months or less.

(f) Restricted cash

Restricted cash represents reserves and amounts set aside pursuant to requirements of various debt agreements and requirements of ISO New England, Inc. Cash reserves segregated from APUC’s cash balances are maintained in accounts administered by a separate agent and disclosed separately as restricted cash as part of other assets (note 12) in these consolidated financial statements. APUC cannot access restricted cash without the prior authorization of parties not related to APUC.

(g) Accounts receivable

Trade accounts receivable are recorded at the invoiced amount and do not bear interest. The Company maintains an allowance for doubtful accounts for estimated losses inherent in its accounts receivable portfolio. In establishing the required allowance, management considers historical losses adjusted to take into account current market conditions and customers’ financial condition, the amount of receivables in dispute, and the receivables aging and current payment patterns. Account balances are charged against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote. The Company does not have any off-balance sheet credit exposure related to its customers.

(h) Natural gas in storage

Natural gas in storage is reflected at weighted average cost or first-in-first-out as required by regulators and represents natural gas and liquefied natural gas that will be utilized in the ordinary course of business of the gas utilities and some generating facilities. Existing rate orders (note 7(c)) and other contracts allow the Company to pass through the cost of gas purchased directly to the customers along with any applicable authorized delivery surcharge adjustments. Accordingly, the recoverable value of gas in storage does not fall below the cost to the Company.

(i) Supplies and consumables inventory

Supplies and consumables inventory (other than capital spares and rotatable spares, which are included in property, plant and equipment) are charged to inventory when purchased and then capitalized to plant or expensed, as appropriate, when installed, used or become obsolete. These items are stated at the lower of cost and replacement cost. Supplies and consumables inventory is included in other current assets.

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2015 and 2014

(in thousands of Canadian dollars, except as noted and per share amounts)

1. Significant accounting policies (continued)

(j) Property, plant and equipment

Property, plant and equipment are recorded at cost. Capitalization of development projects begins when management with the relevant authority authorized and has committed to the funding of the project and it is probable that costs will be realized through the use of the asset or ultimate construction and operation of a facility. Project development costs for rate-regulated entities, including expenditures for preliminary surveys, plans, investigations, environmental studies, regulatory applications and other costs incurred for the purpose of determining the feasibility of capital expansion projects, are capitalized either as property, plant and equipment or regulatory asset when it is determined that recovery of such costs through regulated revenue of the completed project is probable.

The costs of acquiring or constructing property, plant and equipment include the following: materials, labour, contractor and professional services, construction overhead directly attributable to the capital project (where applicable), interest for non-regulated property and allowance for funds used during construction (“AFUDC”) for regulated property. Where possible, individual components are recorded and depreciated separately in the books and records of the Company. Plant and equipment under capital leases are initially recorded at cost determined as the present value of minimum lease payments.

AFUDC represents the cost of borrowed funds and a return on other funds. Under ASC 980, an allowance for funds used during construction projects that are included in rate base is capitalized. This allowance is designed to enable a utility to capitalize financing costs during periods of construction of property subject to rate regulation. For operations that do not apply regulatory accounting, interest related only to debt is capitalized as a cost of construction in accordance with ASC 835, Interest. The interest capitalized that relates to debt reduces interest expense on the consolidated statements of operations. The AFUDC capitalized that relates to equity funds is recorded as interest, dividend, equity and other income on the consolidated statements of operations. 

	2015		2014
Interest capitalized on non-regulated property	$	1,189	$	3,584
AFUDC capitalized on regulated property:
Allowance for borrowed funds	1,657		1,577
Allowance for equity funds	2,425		1,910
Total	$	5,271	$	7,071

Improvements that increase or prolong the service life or capacity of an asset are capitalized. Cost incurred for major expenditures or overhauls that occur at regular intervals over the life of an asset are capitalized and depreciated over the related interval. Maintenance and repair costs are expensed as incurred.

Investment tax credits and government grants related to capital expenditures are recorded as a reduction to the cost of assets and are amortized at the rate of the related asset as a reduction to depreciation expense. Contributions in aid of construction represent amounts contributed by customers, governments and developers to assist with the funding of some or all of the cost of utility capital assets. It also includes amounts initially recorded as advances in aid of construction (note 13(a)) but where the advance repayment period has expired. These contributions are recorded as a reduction in the cost of utility assets and are amortized at the rate of the related asset as a reduction to depreciation expense. Investment tax credits and government grants related to operating expenses such as maintenance and repairs costs are recorded as a reduction of the related expense.

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2015 and 2014

(in thousands of Canadian dollars, except as noted and per share amounts)

1. Significant accounting policies (continued)

(j) Property, plant and equipment (continued)

The Company’s depreciation is based on the estimated useful lives of the depreciable assets in each category and is determined using the straight-line method with the exception of certain wind assets, as described below. The ranges of estimated useful lives and the weighted average useful lives are summarized below:

	Range of useful lives		Weighted average useful lives
	2015	2014	2015	2014
Generation Group	3 - 60	3 - 60	32	35
Distribution Group	5 - 100	5 - 100	42	40
Equipment	5 - 50	5 - 50	14	14

Effective January 1, 2015, the Company changed the depreciation method from the straight-line method to the unit-of-production method for certain components of its wind generating facilities where the useful life of the component is directly related to the amount of production. The benefits of components subject to wear and tear from the power generation process are best reflected through the unit-of-production method. The Company generally uses wind studies prepared by third parties to estimate the total expected production of each component.

This change in the depreciation method results from having better information on the consumption of the benefits of certain individual components that are directly related to production and separately identified in the records of the Company. The change is being recognized prospectively.The impact of the change on the operating results for 2015 was a reduction of depreciation expense of $3,418. The impact on basic and diluted net earnings per share for 2015 was an increase of $0.01. The change is not expected to materially affect net earnings or net earnings per share on an annual basis.

In accordance with regulator-approved accounting policies, when depreciable property, plant and equipment of the Distribution Group are replaced or retired, the original cost plus any removal costs incurred (net of salvage) are charged to accumulated depreciation with no gain or loss reflected in results of operations. Gains and losses will be charged to results of operations in the future through adjustments to depreciation expense. In the absence of regulator-approved accounting policies, gains and losses on the disposition of property, plant and equipment are charged to earnings as incurred. 

(k) Impairment of long-lived assets

APUC reviews property, plant and equipment and intangible assets for impairment whenever events or changes in circumstances indicate the carrying amount may not be recoverable.

Assets held and used: Recoverability of assets expected to be held and used is measured by comparing the carrying amount of an asset to undiscounted expected future cash flows. If the carrying amount exceeds the recoverable amount, the asset is written down to its fair value.

Assets held for sale: Recoverability of assets held for sale is measured by comparing the carrying amount of an asset to its fair value less cost to sell. If the carrying amount exceeds the recoverable amount, the asset is written down to its fair value less estimated costs to sell.

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2015 and 2014

(in thousands of Canadian dollars, except as noted and per share amounts)

1. Significant accounting policies (continued)

(l) Variable interest entities

The Company performs analysis to assess whether its operations and investments represent VIEs. To identify potential VIEs, management reviews contracts under leases, long-term purchase power agreements and jointly-owned facilities. VIEs of which the Company is deemed the primary beneficiary are consolidated. In circumstances where APUC is not deemed the primary beneficiary, the VIE is not consolidated (note 8(a) and (b)).

The Company has equity and notes receivable interests in two power generating facilities. APUC has determined that both entities are considered a VIE mainly based on total equity at risk not being sufficient to permit the legal entity to finance its activities without additional subordinated financial support. The key decisions that affect the generating facilities’ economic performance relate to siting, permitting, technology, construction, operations and maintenance and financing. As APUC has both the power to direct the activities of the entities that most significantly impact its economic performance and the right to receive benefits or the obligation to absorb losses of the entities that could potentially be significant to the entity, the Company is considered the primary beneficiary.

Total net book value of generating assets and long-term debt of these facilities amounts to $104,243 (2014 - $112,344) and $62,138 (2014 - $59,449), respectively. The debt only has recourse over the generating assets. The financial performance of these facilities reflected on the consolidated statements of operations includes non-regulated energy sales of $18,651 (2014 - $11,218), operating expenses and amortization of $5,645 (2014 - $3,418) and interest expense of $4,407 (2014 - $3,820).

(m) Long-term investments and notes receivable

Investments in which APUC has significant influence but not control are accounted using the equity method. Equity-method investments are initially measured at cost including transaction costs and interest when applicable. APUC records its share in the income or loss of its investees in interest, dividend, equity and other income in the consolidated statements of operations.

Notes receivable are financial assets with fixed or determined payments that are not quoted in an active market. Notes receivable are initially recorded at cost, which is generally face value. Subsequent to acquisition, the notes receivable are recorded at amortized cost using the effective interest method. The Company acquired these notes receivable as long-term investments and does not intend to sell these instruments prior to maturity. Interest from long-term investments is recorded as earned.

If a loss in value of a long-term investment is considered other than temporary, an allowance for impairment on the investment is recorded for the amount of that loss. An allowance for impairment loss on notes receivable is recorded if it is expected that the Company will not collect all principal and interest contractually due. The impairment is measured based on the present value of expected future cash flows discounted at the note’s effective interest rate.

(n) Pension and other post-employment plans

The Company has established defined contribution pension plans, defined benefit pension plans, and other post-employment benefit (“OPEB”) plans for its various employee groups in Canada and the United States. Employer contributions to the defined contribution pension plans are expensed as employees render service. The Company recognizes the funded status of its defined benefit pension plans and OPEB plans on the consolidated balance sheets. The Company’s expense and liabilities are determined by actuarial valuations, using assumptions that are evaluated annually as of December 31, including discount rates, mortality, assumed rates of return, compensation increases, turnover rates and healthcare cost trend rates. The impact of modifications to those assumptions and modifications to prior services are recorded as actuarial gains and losses in accumulated other comprehensive income (“AOCI”) and amortized to net periodic cost over future periods using the corridor method. The costs of the Company’s pension for employees are expensed over the periods during which employees render service and are recognized as part of administrative expenses in the consolidated statements of operations.

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2015 and 2014

(in thousands of Canadian dollars, except as noted and per share amounts)

1. Significant accounting policies (continued)

(o) Asset retirement obligations

The Company recognizes a liability for asset retirement obligations based on the fair value of the liability when incurred, which is generally upon acquisition, during construction or through the normal operation of the asset. Concurrently, the Company also capitalizes an asset retirement cost, equal to the estimated fair value of the asset retirement obligation, by increasing the carrying value of the related long-lived asset. The asset retirement costs are depreciated over the asset’s estimated useful life and are included in depreciation and amortization expense on the consolidated statements of operations, or regulatory assets when the amount is recoverable through rates. Increases in the asset retirement obligation resulting from the passage of time are recorded as accretion of asset retirement obligation in the consolidated statements of operations, or regulatory assets when the amount is recoverable through rates. Actual expenditures incurred are charged against the obligation.

(p) Share-based compensation

The Company has several share-based compensation plans: a share option plan; an employee share purchase plan (“ESPP”); a deferred share unit (“DSU”) plan; and a performance share unit (“PSU”) plan. Equity classified awards are measured at the grant date fair value of the award. The Company estimates grant date fair value of options using the Black-Scholes option pricing model. The fair value is recognized over the vesting period of the award granted, adjusted for estimated forfeitures. The compensation cost is recorded as administrative expense in the consolidated statements of operations and contributed surplus in equity. Contributed surplus is reduced as the awards are exercised, and the amount initially recorded in contributed surplus is credited to common shares.

(q) Non-controlling interests

Non-controlling interests represent the portion of equity ownership in subsidiaries that is not attributable to the equity holders of APUC. Non-controlling interests are initially recorded at fair value and subsequently adjusted for the proportionate share of earnings and other comprehensive income (“OCI”) attributable to the non-controlling interests and any dividends or distributions paid to the non-controlling interests.

If a transaction results in the acquisition of all, or part, of a non-controlling interest in a consolidated subsidiary, the acquisition of the non-controlling interest is accounted for as an equity transaction. No gain or loss is recognized in net earnings or comprehensive income as a result of changes in the non-controlling interest, unless a change results in the loss of control by the Company.

Certain of the Company’s U.S. based wind and solar businesses are organized as limited liability corporations and partnerships and have non-controlling Class A membership equity investors (“Class A partnership units”) which are entitled to allocations of earnings, tax attributes and cash flows in accordance with contractual agreements. The share of earnings attributable to the non-controlling interest holders in these subsidiaries is calculated using the Hypothetical Liquidation at Book Value (“HLBV”) method of accounting. The HLBV method uses a balance sheet approach, which measures the allocation of income or loss of the Class A partnership units in each period by calculating the change in the amount of distribution the partners would contractually be entitled to based on a hypothetical liquidation of the book value carrying amounts of the entity at the beginning of a reporting period compared to the end of that period (note 18).

Equity instruments subject to redemption upon the occurrence of uncertain events not solely within APUC’s control are classified as temporary equity on the consolidated balance sheets. The Company records temporary equity at issuance based on cash received less any transaction costs. As needed, the Company reevaluates the classification of its redeemable instruments, as well as the probability of redemption. If the redemption amount is probable or currently redeemable, the Company records the instruments at their redemption value. Increases or decreases in the carrying amount of a redeemable instrument are recorded within deficit. When the redemption feature lapses or other events cause the classification of an equity instrument as temporary equity to be no longer required, the existing carrying amount of the equity instrument is reclassified to permanent equity at the date of the event that caused the reclassification.

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2015 and 2014

(in thousands of Canadian dollars, except as noted and per share amounts)

1. Significant accounting policies (continued)

(r) Recognition of revenue

Revenue derived from non-regulated energy generation sales, which are mostly under long-term power purchase contracts, is recorded at the time electrical energy is delivered.

Revenue related to utility electricity and natural gas sales and distribution are recorded when the electricity or natural gas is delivered. At the end of each month, the electricity and natural gas delivered to the customers from the date of their last meter read to the end of the month is estimated and the corresponding unbilled revenue is recorded. These estimates of unbilled revenue and sales are based on the ratio of billable days versus unbilled days, amount of electricity or natural gas procured during that month, historical customer class usage patterns, weather, line loss, unaccounted-for gas and current tariffs.

Revenue for the Company’s Calpeco Electric System, Peach State Gas System and New England Gas System is subject to a revenue decoupling mechanism approved by their respective regulator which require to charge approved annual delivery revenue on a systematic basis over the fiscal year. As a result, the difference between delivery revenue calculated based on metered consumption and approved delivery revenue is recorded as a regulatory asset or liability to reflect future recovery or refund, respectively, from customers (note 7(e)).

Water reclamation and distribution revenues are recorded when water is processed or delivered to customers. At the end of each month, the water delivered and wastewater collected from the customers from the date of their last meter read to the end of the month is estimated and the corresponding unbilled revenue is recorded. These estimates of unbilled revenue are based on the ratio of billable days versus unbilled days, amount of water procured and collected during that month, historical customer class usage patterns and current tariffs.

On occasion, a utility is permitted to implement new rates that have not been formally approved by the regulatory commission, which are subject to refund. The Company recognizes revenue based on the interim rate and if needed, establishes a reserve for amounts that could be refunded based on experience for the jurisdiction in which the rates were implemented.

Revenue is recorded net of sales taxes. 

During the year, the Company settled insurance claims for business interruption at some of its generation facilities under repairs and as a result recognized revenue of $581 (2014 - $1,227).

(s) Foreign currency translation

The Company’s reporting currency is the Canadian dollar.

The Company’s U.S. operations are determined to have the U.S. dollar as their functional currency since the preponderance of operating, financing and investing transactions are denominated in U.S. dollars. The financial statements of these operations are translated into Canadian dollars using the current rate method, whereby assets and liabilities are translated at the rate prevailing at the balance sheet date, and revenue and expenses are translated using average rates for the period. Unrealized gains or losses arising as a result of the translation of the financial statements of these entities are reported as a component of OCI and are accumulated in a component of equity on the consolidated balance sheets, and are not recorded in income unless there is a complete or substantially complete sale or liquidation of the investment.  

(t) Income taxes

Income taxes are accounted for using the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. A valuation allowance is recorded against deferred tax assets to the extent that it is considered more likely than not that the deferred tax asset will not be realized. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in earnings in the period that includes the date of enactment. Income tax credits are treated as a reduction to current income tax expense in the year the credit arises or future periods to the extent that realization of such benefit is more likely than not.

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2015 and 2014

(in thousands of Canadian dollars, except as noted and per share amounts)

1. Significant accounting policies (continued)

(t) Income taxes (continued)

The organizational structure of APUC and its subsidiaries is complex and the related tax interpretations, regulations and legislation in the tax jurisdictions in which they operate are continually changing. As a result, there can be tax matters that have uncertain tax positions. The Company recognizes the effect of income tax positions only if those positions are more likely than not of being sustained. Recognized income tax positions are measured at the largest amount that is greater than 50% likely of being realized. Changes in recognition or measurement are reflected in the period in which the change in judgment occurs.

(u) Financial instruments and derivatives

Accounts receivable and notes receivable are measured at amortized cost. Long-term debt and Series C preferred shares are measured at amortized cost using the effective interest method, adjusted for the amortization or accretion of premiums or discounts.

Transaction costs that are directly attributable to the acquisition of financial assets are accounted for as part of the asset’s carrying value at inception. Transaction costs related to a recognized debt liability are presented in the consolidated balance sheets as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts and premiums. Costs of arranging the Company’s revolving credit facilities and intercompany loans are recorded in other assets. Deferred financing costs, premiums and discounts on long-term debt are amortized using the effective interest method while deferred financing costs relating to the revolving credit facilities and intercompany loans are amortized on a straight-line basis over the term of the respective instrument.

The Company uses derivative financial instruments as one method to manage exposures to fluctuations in exchange rates, interest rates and commodity prices. APUC recognizes all derivative instruments as either assets or liabilities in the consolidated balance sheets at their respective fair values. The fair value recognized on derivative instruments executed with the same counterparty under a master netting arrangement are presented on a gross basis on the consolidated balance sheets. The amounts that could net settle are not significant. The Company applies hedge accounting to some of its financial instruments used to manage its foreign currency risk exposure, interest risk and price risk exposure associated with sales of generated electricity.

For derivatives designated in a cash flow hedge relationship, the effective portion of the change in fair value is recognized in OCI. The ineffective portion is immediately recognized in earnings. The amount recognized in AOCI is reclassified to earnings in the same period as the hedged cash flows affect earnings under the same line item in the consolidated statements of operations as the hedged item. If the hedging instrument no longer meets the criteria for hedge accounting, expires or is sold, terminated, exercised, or the designation is revoked, then hedge accounting is discontinued prospectively. The amount remaining in AOCI is transferred to the consolidated statements of operations in the same period that the hedged item affects earnings. If the forecasted transaction is no longer expected to occur, then the balance in AOCI is recognized immediately in earnings.

Foreign currency gain or loss on derivative or financial instruments designated as a hedge of the foreign currency exposure of a net investment in foreign operations that are effective as a hedge are reported in the same manner as the translation adjustment (in OCI) related to the net investment. To the extent that the hedge is ineffective, such differences are recognized in earnings.

The Company’s electric distribution and thermal generation facilities enter into power and gas purchase contracts for load serving and generation requirements. These contracts meet the exemption for normal purchase and normal sales and as such, are not required to be recorded at fair value as derivatives and are accounted for on an accrual basis. Counterparties are evaluated on an ongoing basis for non-performance risk to ensure it does not impact the conclusion with respect to this exemption.

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2015 and 2014

(in thousands of Canadian dollars, except as noted and per share amounts)

1. Significant accounting policies (continued)

(v) Fair value measurements

The Company utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs to the extent possible. The Company determines fair value based on assumptions that market participants would use in pricing an asset or liability in the principal or most advantageous market. When considering market participant assumptions in fair value measurements, the following fair value hierarchy distinguishes between observable and unobservable inputs, which are categorized in one of the following levels:

• Level 1 Inputs: Unadjusted quoted prices in active markets for identical assets or liabilities accessible to the reporting entity at the measurement date.

• Level 2 Inputs: Other than quoted prices included in Level 1, inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the asset or liability.

• Level 3 Inputs: Unobservable inputs for the asset or liability used to measure fair value to the extent that observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset or liability at the measurement date.

(w) Commitments and contingencies

Liabilities for loss contingencies arising from environmental remediation, claims, assessments, litigation, fines, and penalties and other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. Legal costs incurred in connection with loss contingencies are expensed as incurred.

(x) Use of estimates

The preparation of financial statements 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 these consolidated financial statements and the reported amounts of revenue and expenses during the year. Actual results could differ from those estimates. During the years presented, management has made a number of estimates and valuation assumptions, including the useful lives and recoverability of property, plant and equipment, intangible assets and goodwill; the recoverability of notes receivable and long-term investments; the recoverability of deferred tax assets; assessments of unbilled revenue; pension and OPEB obligations; timing effect of regulated assets and liabilities; contingencies related to environmental matters; the fair value of assets and liabilities acquired in a business combination; and, the fair value of financial instruments. These estimates and valuation assumptions are based on present conditions and management’s planned course of action, as well as assumptions about future business and economic conditions. Should the underlying valuation assumptions and estimates change, the recorded amounts could change by a material amount.

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2015 and 2014

(in thousands of Canadian dollars, except as noted and per share amounts)

2.     Recently issued accounting pronouncements

(a) Recently adopted accounting pronouncements    

The FASB issued ASU 2015-17 Income Taxes (Topic 740) to simplify the presentation of deferred income taxes. This ASU requires that deferred tax liabilities and assets be classified as non-current in a classified statement of financial position. The current requirement that deferred tax liabilities and assets of a tax-paying component of an entity be offset and presented as a single amount is not affected by this ASU. The Company retrospectively adopted this ASU in the fourth quarter of 2015. As a result, a deferred tax asset and a deferred tax liability of $7,210 and $3,702, respectively, that were presented as current as of December 31, 2014 have been reclassified to non-current deferred tax asset and deferred tax liability on the consolidated balance sheets.

The FASB issued ASU 2015-13 Derivatives and Hedging (Topic 815): Application of the Normal Purchases and Normal Sales Scope Exception to Certain Electricity Contracts within Nodal Energy Markets. This ASU clarifies that the use of locational marginal pricing by an independent system operator does not constitute net settlement of a contract for the purchase or sale of electricity on a forward basis that necessitates transmission through, or delivery to a location within, a nodal energy market. Consequently, the use of locational marginal pricing by the independent system operator does not cause that contract to fail to meet the physical delivery criterion of the normal purchases and normal sales scope exception. The adoption of this ASU in the third quarter of 2015 had no impact on the Company’s consolidated financial statements.    

The FASB issued ASU 2015-10, Technical Corrections and Improvements, to clarify the codification, correct unintended application of guidance, or make minor improvements to the codification. The adoption of this ASU in the second quarter of 2015 had no impact on the Company’s consolidated financial statements.

The FASB issued ASU 2015-04, Compensation: Retirement Benefits (Subtopic 715), to provide a practical expedient that permits an entity with a fiscal year-end that does not coincide with a month-end and an entity that has a significant event in an interim period that calls for a remeasurement of defined benefit plan assets and obligations to measure defined benefit plan assets and obligations using the month-end that is closest to the entity’s fiscal year-end or significant event. The Company adopted this ASU prospectively in the second quarter of 2015 and as a result, remeasured amendments to its pension plans, made during the second quarter, using the month-end closest to the amendments.

The FASB issued ASU 2015-03, Interest: Imputation of Interest (Subtopic 835-30), to simplify presentation of debt issuance costs. The amendments in this ASU require that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected. Effective January 1, 2015, the Company applied this ASU retrospectively to all prior periods presented in the financial statements. As a result, deferred financing costs of $8,304 as of December 31, 2014 that were previously presented as other assets on the consolidated balance sheets have been reclassified as a deduction from the carrying amount of the related long-term debt. In accordance with ASU 2015-15 Interest: Imputation of Interest (Subtopic 835-30), the Company continues to present deferred issuance costs related to its revolving credit facilities and related instruments as other assets.

The FASB issued ASU 2014-08, Presentation of Financial Statements (Topic 205) and Property, Plant and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. This newly issued accounting standard raises the threshold for a disposal to qualify as a discontinued operation and requires new disclosures of both discontinued operations and certain other disposals that do not meet the definition of a discontinued operation. Effective January 1, 2015, the Company adopted this ASU prospectively and as a result, its adoption had no impact on discontinued operations reported in prior periods.

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2015 and 2014

(in thousands of Canadian dollars, except as noted and per share amounts)

2. Recently issued accounting pronouncements (continued)

(b) Recently issued accounting guidance not yet adopted

The FASB issued ASU 2016-02, Leases (Topic 842) to increase transparency and comparability among organizations utilizing leases. This ASU requires lessees to recognize the assets and liabilities arising from all leases on the balance sheet, but the effect of leases in the statement of operations and the statement of cash flows is largely unchanged. The standard is effective for fiscal years and interim periods beginning after December 15, 2018. Early adoption is permitted. The Company is currently in the process of evaluating the impact of adoption of this standard on its consolidated financial statements.

The FASB issued ASU 2016-01, Financial Instruments - Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities to simplify the measurement, presentation, and disclosure of financial instruments. The standard is effective for fiscal years and interim periods beginning after December 15, 2017. Early adoption is permitted. The Company is currently in the process of evaluating the impact of adoption of this standard on its consolidated financial statements.

The FASB issued ASU 2015-16 Business Combinations (Topic 805): Simplifying the Accounting for Measurement Period Adjustments. Under this ASU, adjustments to the provisional amounts recorded in a business combination continue to be calculated as if the accounting had been completed at the acquisition date. However, the ASU eliminates the requirement to retrospectively account for those adjustments and instead requires recognition in the period that the adjustments are identified. The amendments in this ASU should be applied prospectively to adjustments to provisional amounts that occur after December 15, 2015 with earlier application permitted for financial statements that have not been issued. As the measurement period has closed for the Company’s past acquisitions, the consolidated financial statements are not expected to be impacted, in that respect, by the adoption of this standard.

The FASB issued ASU 2015-11, Inventory (Topic 330): Simplifying the Measurement of Inventory, to simplify the subsequent measurement of inventory by replacing the current lower of cost and market test with a lower of cost and net realizable value test. The prospective application of this standard is effective for fiscal years and interim periods beginning after December 15, 2016. Early adoption is permitted. The adoption of this standard is not expected to have an impact on the Company’s financial position or results of operations.

The FASB issued ASU 2015-05, Intangibles: Goodwill and Other Internal-Use Software (Subtopic 350-40), to provide guidance to customers about whether a cloud computing arrangement includes a software license. This ASU can be adopted either (1) prospectively to all arrangements entered into or materially modified after the effective date or (2) retrospectively. The standard is effective for fiscal years and interim periods beginning after December 15, 2015. Early adoption is permitted. The prospective adoption of this standard is not expected to have an impact on the Company’s financial position or results of operations.

The FASB issued ASU 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis, which ends the deferral granted to investment companies from applying the VIE guidance and makes targeted amendments to the current consolidation guidance. Some of the more notable amendments are (1) the identification of variable interests when fees are paid to a decision maker or service provider, (2) the VIE characteristics for a limited partnership or similar entity and (3) the primary beneficiary determination. This ASU may be applied using a modified retrospective approach by recording a cumulative-effect adjustment to equity as of the beginning of the fiscal year of adoption or retrospectively to all prior periods presented in the financial statements. The standard is effective for periods beginning after December 15, 2015. Early adoption is permitted. The Company is currently in the process of evaluating the impact of adoption of this standard on its consolidated financial statements.

The FASB issued ASU 2015-01, Income Statement: Extraordinary and Unusual Items (Subtopic 225-20), to simplify income statement classification by removing the concept of extraordinary items from U.S. GAAP. As a result, items that are both unusual and infrequent will no longer be separately reported net of tax after continuing operations. This ASU may be applied prospectively or retrospectively to all prior periods presented in the financial statements. The standard is effective for periods beginning after December 15, 2015. Early adoption is permitted, but only as of the beginning of the fiscal year of adoption. The adoption of this standard is not expected to have an impact on the Company’s results of operations.

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2015 and 2014

(in thousands of Canadian dollars, except as noted and per share amounts)

2. Recently issued accounting pronouncements (continued)

(b) Recently issued accounting guidance not yet adopted (continued)

The FASB issued ASU 2014-16, Derivatives and Hedging (Topic 815): Determining Whether the Host Contract in a Hybrid Financial Instrument Issued in the Form of a Share is More Akin to Debt or to Equity. ASU 2014-16 clarifies how current guidance should be interpreted in evaluating the economic characteristics and risks of a host contract in a hybrid financial instrument that is issued in the form of a share. In addition, ASU 2014-16 clarifies that in evaluating the nature of a host contract, an entity should assess the substance of the relevant terms and features (that is, the relative strength of the debt-like or equity-like terms and features given the facts and circumstances) when considering how to weigh those terms and features. The effects of initially adopting ASU 2014-16 should be applied on a modified retrospective basis to existing hybrid financial instruments issued in a form of a share as of the beginning of the fiscal year for which the amendments are effective. Retrospective application is permitted to all relevant prior periods. ASU 2014-16 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. Early adoption is permitted. The Company is currently in the process of evaluating the impact of adoption of this standard on its consolidated financial statements.

The FASB issued ASU 2014-15, Presentation of Financial Statements - Going Concern. This new standard provides that in connection with preparing financial statements for each annual and interim reporting period, an entity’s management should evaluate whether there are conditions or events that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the date that the financial statements are issued. This ASU will be effective for the annual reporting period ending after December 15, 2016, and for annual and interim periods thereafter. Early application is permitted. The adoption of this standard is not expected to have an impact on the Company’s financial position or results of operations.

The FASB issued ASU 2014-12, Compensation-Stock Compensation (Topic 718): Accounting for Share-Based Payments When the Terms of an Award Provide That a Performance Target Could Be Achieved after the Requisite Service Period. This newly issued accounting standard is intended to resolve the diverse accounting treatment of those awards in practice. This ASU is required to be applied for fiscal years and interim periods beginning after December 15, 2015. The adoption of this standard is not expected to have an impact on the Company’s financial position or results of operations.

The FASB and the International Accounting Standards Board have jointly issued a new revenue recognition standard codified in U.S. GAAP as ASU 2014-09, Revenue from Contracts with Customers (Topic 606). This newly issued accounting standard provides accounting guidance for all revenue arising from contracts with customers and affects all entities that enter into contracts to provide goods or services to their customers unless the contracts are in the scope of other U.S. GAAP requirements, such as the leasing literature. During the quarter, the FASB approved a one year deferral of the effective date of this new revenue standard and as such, it is now required to be applied for fiscal years and interim periods beginning after December 15, 2017 using either a full retrospective approach for all periods presented in the period of adoption or a modified retrospective approach. The Company is currently assessing the impact the adoption of this standard might have on its financial position or results of operations.

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2015 and 2014

(in thousands of Canadian dollars, except as noted and per share amounts)

3. Business acquisitions and development projects

(a) Acquisition of Empire

Subsequent to year-end, on February 9, 2016, the Company entered into an agreement and plan of merger pursuant to which, a subsidiary of Liberty Utilities Co. will merge with and into The Empire District Electric Company and its subsidiaries (“Empire”), and Empire will survive the merger and become a wholly owned indirect subsidiary of the Company. Empire is a Joplin, Missouri based regulated electric, gas and water utility, serving customers in Missouri, Kansas, Oklahoma and Arkansas. 

Empire shareholders will receive U.S.$34.00 per common share in cash, which represents an aggregate purchase price of approximately $3,400,000 (U.S.$2,400,000), which includes the assumption of approximately $1,300,000 (U.S.$900,000) of debt.

The closing of the acquisition, which is expected to occur in early 2017, is subject to customary closing conditions, including the approval of Empire’s common shareholders, and the receipt of certain state and federal regulatory and government approvals.

On February 9, 2016, the Company obtained a $2,200,000 (U.S. $1,600,000) bridge financing commitment for the acquisition from a syndicate of banks (note 9).

On March 1, 2016, the Company issued $1,000,000 aggregate principal amount of 5.0% convertible unsecured subordinated debentures represented by instalment receipts (the “Debentures” or the “Debenture Offering”) and received the first instalment of $333,000. On March 9, 2016, the underwriters exercised their option to purchase $150,000 additional Debentures and received the first instalment of $49,950. The Debentures are expected to convert to common shares of the Company upon the closing of the acquisition of Empire (note 25).

(b) Acquisition of Park Water System

Subsequent to year-end, on January 8, 2016, the Company completed the acquisition of Western Water Holdings, LLC which is the parent company of Park Water Company (“Park Water System”), a regulated water distribution utility. Park Water System owns and operates three regulated water utilities engaged in the production, treatment, storage, distribution, and sale of water in southern California and western Montana. The total purchase price for the Park Water System is U.S.$341,750, including debt assumed of U.S.$91,750 and is subject to certain closing adjustments. All costs related to the acquisition have been expensed through the consolidated statements of operations.

Due to the timing of the acquisition, the Company has not completed the fair value measurements of the assets acquired and liabilities assumed. The Company will continue to review information and perform further analysis prior to finalizing the fair value of the consideration paid and the fair value of the assets acquired and liabilities assumed.

Mountain Water Company is currently the subject of a condemnation proceeding by the city of Missoula. It is not known when the condemnation proceeding will conclude or whether the City of Missoula will ultimately take possession of Mountain Water Company. The City’s right to take Mountain Water Company is currently on appeal before the Montana Supreme Court, which is set to hear the appeal on April 22, 2016. If the City of Missoula prevails on appeal and ultimately takes possession of Mountain Water Company, the compensation to be paid by the City of Missoula for such taking will be the value of the utility plus accrued interest and attorney’s fees as determined by the Montana court.

(c) Commercial operation of Morse Wind Facility

In 2015, the Company completed construction of a 23 MW wind generating facility located near Morse, Saskatchewan (“Morse Wind Facility”). Sale of power to the utility commenced in March 2015 at rates equivalent to those under the power purchase agreement. Commercial operation date as defined in the power purchase agreement occurred on April 22, 2015. The cost of the generating assets of $65,016 is recorded as property, plant and equipment on the consolidated balance sheets while $16,709 is recorded as intangible Assets, for a total investment of $81,725. The weighted average useful life of the Morse Wind Facility is 35 years.

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2015 and 2014

(in thousands of Canadian dollars, except as noted and per share amounts)

3. Business acquisitions and development projects (continued)

(d) Acquisition of New Hampshire Gas

On January 2, 2015, the Distribution Group completed the acquisition of New Hampshire Gas, a regulated propane gas distribution utility located in Keene, New Hampshire. The New Hampshire Gas System services approximately 1,200 propane gas distribution customers. Total purchase price for the New Hampshire Gas System is U.S.$3,161.

(e) Commercial operation of Bakersfield Solar I Facility

In 2014, the Company completed construction a 20 MWac solar powered generating facility located in Kern County, California (“Bakersfield I Solar Facility”) which was placed in service on December 31, 2014. The Bakersfield I Solar Facility started selling power at the power purchase agreement price on May 15, 2015. The cost of these generating assets amounts to U.S.$57,160 and is recorded as property, plant and equipment on the consolidated balance sheets. The cost of the original development project is subject to certain adjustments which are expected to be finalized in 2016. The weighted average useful life of the Bakersfield Solar I Facility is 34 years.

The Bakersfield I Solar Facility is controlled by a subsidiary of APUC (the “Bakersfield I Partnership”). The Class A partnership units are owned by a third-party (the “Tax Equity Investor”) who funded a total of U.S.$22,438 to the project. With its partnership interest, the Tax Equity Investor will receive the majority of the tax attributes associated with the project.

During a six-month period in year 2020, the Tax Investor has the right to withdraw from the Bakersfield I Solar Facility and require the Company to redeem its remaining interests for cash. As a result, the Company accounts for this interest as “Redeemable non-controlling interest” outside of permanent equity on the consolidated balance sheets. Redemption is not considered probable as of December 31, 2015.

(f) Commercial operation of Saint-Damase Wind Facility

In 2014, the Company completed construction of a 24 MW wind powered generating facility located near St. Damase, Quebec (“Saint-Damase Wind Facility”) which achieved commercial operation on December 2, 2014. The cost of these generating assets amounts to $64,155 and is recorded as property, plant and equipment on the consolidated balance sheets. The weighted average useful life of the Saint-Damase Wind Facility is 34 years.

(g) Acquisition of White Hall Water System

On May 30, 2014, the Distribution Group acquired the assets of the White Hall Water System, a regulated water distribution and wastewater treatment utility located in White Hall, Arkansas. The White Hall Water System serves approximately 1,900 water distribution and 2,400 wastewater treatment customers. Total purchase price for the White Hall Water System assets, adjusted for certain working capital and other closing adjustments, is approximately U.S.$4,499.

(h) Acquisition of non-controlling interest in U.S. wind farms

On March 31, 2014, the Company acquired the 40% interest in Wind Portfolio SponsorCo, LLC (“Wind Portfolio SponsorCo”) for approximately U.S.$115,000. Wind Portfolio SponsorCo indirectly holds the interests in Sandy Ridge, Senate and Minonk Wind acquired in 2012. As a result of the transaction, the Generation Group now owns 100% of Wind Portfolio SponsorCo’s Class B partnership units resulting in the elimination of the non-controlling interest in respect of the Class B partnership units of Wind Portfolio SponsorCo as follows:

Elimination of non-controlling interest in Class B partnership units	$	205,796
Non-controlling interest portion of currency translation adjustment recorded to AOCI	(21,029		)
Non-controlling interest portion of unrealized gain on cash flow hedges recorded to AOCI	(2,543		)
Decrease in deferred income tax asset	(32,551		)
Additional paid-in capital	(22,552		)
Cash	$	127,121

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2015 and 2014

(in thousands of Canadian dollars, except as noted and per share amounts)

3. Business acquisitions and development projects (continued)

(i) Commercial operation of Cornwall Solar Facility

In 2014, the Company completed the construction of a 10 MWac solar powered generating facility located near Cornwall, Ontario (“Cornwall Solar Facility”) which achieved commercial operation on March 27, 2014. The cost of these generating assets of $40,090 is recorded as property, plant and equipment while $7,243 is recorded as intangible assets, for a total investment of $47,333. The weighted average useful life of the Cornwall Solar Facility is 33 years.

(j) Acquisition of New England Gas System

On December 20, 2013, the Company acquired certain regulated natural gas distribution utility assets (the “New England Gas System”) located in the State of Massachusetts. Total purchase price for the New England Gas System, net of the debt assumed, is $67,010 (U.S.$62,745), including the purchase price adjustment of U.S.$3,108 finalized in 2014.

In 2014, the Company received additional information which was used to refine the estimates for fair value of assets acquired and liabilities assumed. The key retrospective adjustments to the assets and liabilities were an increase to the regulatory asset for pension of U.S.$2,701, a decrease of property, plant and equipment of U.S.$1,190, an increase of the environmental obligation of U.S.$2,467 and an increase of the pension obligation of U.S.$772.

(k) Acquisition of Shady Oaks Wind Facility

Effective January 1, 2013, the Company acquired the 109.5 MW Shady Oaks wind-powered generating facility (“Shady Oaks Wind Facility”). The purchase agreement provides for final purchase price adjustments based on working capital at the acquisition date, energy generated by the project and basis differences between the relevant node and hub prices which are expected to be finalized in 2016. Changes in measurement of the final purchase price adjustment subsequent to December 31, 2013, the end of the business combination measurement period, are recorded in current period operations. To that effect, no gain or loss was recognized in 2015 (2014 - U.S.$1,133).

4. Accounts receivable

Accounts receivable as of December 31, 2015 include unbilled revenue of $49,002 (2014 - $52,880) from the Company’s regulated utilities. Accounts receivable as of December 31, 2015 are presented net of allowance for doubtful accounts of $7,966 (2014 - $7,229).

5. Property, plant and equipment

Property, plant and equipment consist of the following: 

2015
	Cost		Accumulated depreciation		Net book value
Generation	$	2,138,748	$	358,200	$	1,780,548
Distribution	2,075,059		265,741		1,809,318
Land	23,258		—		23,258
Equipment and other	129,555		37,443		92,112
Construction in progress
Generation	64,779		—		64,779
Distribution	103,669		—		103,669
	$	4,535,068	$	661,384	$	3,873,684

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2015 and 2014

(in thousands of Canadian dollars, except as noted and per share amounts)

5. Property, plant and equipment (continued)

2014
	Cost		Accumulated depreciation		Net book value
Generation	$	1,827,247	$	270,746	$	1,556,501
Distribution	1,555,289		147,726		1,407,563
Land	19,347		—		19,347
Equipment and other	119,367		29,526		89,841
Construction in progress
Generation	82,840		—		82,840
Distribution	122,330		—		122,330
	$	3,726,420	$	447,998	$	3,278,422

Generation assets include cost of $158,514 (2014 - $155,629) and accumulated depreciation of $38,507 (2014 - $34,013) related to facilities under capital lease or owned by consolidated VIEs. Depreciation expense of facilities under capital lease was $2,117 (2014 - $2,274).

Investments tax credits, government grants and contributions received in aid of construction of $9,623 (2014 - $362) have been credited to the cost of the assets. Water and wastewater distribution assets include expansion costs of $1,000 on which the Company does not currently earn a return. 

6. Intangible assets and goodwill

Intangible assets consist of the following:

2015
	Cost		Accumulated amortization		Net book value
Power sales contracts	$	78,725	$	40,244	$	38,481
Customer relationships	37,083		10,371		26,712
Interconnection agreements	13,000		230		12,770
	$	128,808	$	50,845	$	77,963

2014
	Cost			Accumulated amortization		Net book value
Power sales contracts	$	64,605		$	33,704	$	30,901
Customer relationships	31,094			7,984		23,110
Interconnection agreements	—		—	—		—
	$	95,699		$	41,688	$	54,011

Estimated amortization expense for intangible assets for the next year is $5,420, $3,620 in year two, $3,250 in year three, $3,200 in year four and $3,160 in year five.

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2015 and 2014

(in thousands of Canadian dollars, except as noted and per share amounts)

6. Intangible assets and goodwill (continued)

Changes in goodwill are as follows:

	Distribution Group
Balance, January 1, 2014	$	84,647
Foreign exchange	7,681
Balance, December 31, 2014	$	92,328
Business acquisitions	290
Foreign exchange	17,875
Balance, December 31, 2015	$	110,493

7. Regulatory matters

The Company’s regulated utility operating companies are subject to regulation by the public utility commissions of the states in which they operate. The respective public utility commissions have jurisdiction with respect to rate, service, accounting policies, issuance of securities, acquisitions and other matters. These utilities operate under cost-of-service regulation as administered by these state authorities. The Company’s regulated utility operating companies are accounted for under the principles of ASC 980. Under ASC 980, regulatory assets and liabilities that would not be recorded under U.S. GAAP for non-regulated entities are recorded to the extent that they represent probable future revenue or expenses associated with certain charges or credits that will be recovered from or refunded to customers through the rate-setting process.

At any given time, the Company can have several regulatory proceedings underway. The financial effects of these proceedings are reflected in the consolidated financial statements based on regulatory approval obtained to the extent that there is a financial impact during the applicable reporting period.

On February 18, 2016, the Georgia Public Service Commission approved a Final Order for the Peach State Gas System of a U.S.$2,725 revenue increase effective March 1, 2016.

On February 10, 2016, the New England Gas System received a Final Order from the Massachusetts Department of Public Utilities approving an annual revenue increase of U.S.$7,800 effective March 1, 2016.

On June 26, 2015, the EnergyNorth Gas System received a Final Order from the New Hampshire Public Utility Commission approving a settlement agreement allowing for a U.S.$12,400 revenue increase effective July 1, 2015.

On March 12, 2015, the Pine Bluff Water System received a Final Order from the Arkansas Public Service Commission approving a revenue increase of U.S.$1,087 effective March 15, 2015.

On February 11, 2015, the Midstates Gas System received a Final Order from the Illinois Commerce Commission approving a rate increase of U.S.$4,625 effective February 20, 2015.

On March 17, 2014, the Granite State Electric System received a Final Order from the New Hampshire Public Utilities Commission approving a rate increase of U.S.$10,875 consisting of U.S.$9,760 in base rates and an additional U.S.$1,115 for incremental capital expended after the test year.  In addition, the Order allows for a one time recovery of rate case expenses of  U.S.$390.  The new rates were effective as of April 1, 2014 for services rendered on and after July 1, 2013.

On April 18, 2014, the LPSCo Water System received a Final Order from the Arizona Corporation Commission approving a rate increase of U.S.$1,767 in connection with its rate application filed on February 28, 2013. The new rates became effective on May 1, 2014.

In May 2014, the Peach State Gas System received a Final Order from the Georgia Public Service approving an annual revenue increase of U.S.$3,235 in connection with its annual GRAM filing on October 1, 2013.  The new rates were effective as of June 1, 2014 for services rendered on and after February 1, 2014.

On December 3, 2014, the Midstates Gas System received a Final Order from the Missouri Public Service Commission approving a rate increase of U.S.$4,868 effective January 2, 2015.

On December 4, 2014, the Peach State Gas System received a Final Order from the Georgia Public Service approving an annual revenue increase of U.S.$3,680 in connection with its annual GRAM filing on October 1, 2014.  The new rates are effective as of February 1, 2015.

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2015 and 2014

(in thousands of Canadian dollars, except as noted and per share amounts)

7. Regulatory matters (continued)

Regulatory assets and liabilities consist of the following: 

	2015			2014
Regulatory assets
Environmental remediation (a)	$	116,747		$	102,735
Pension and post-employment benefits (b)	69,537			63,512
Commodity costs adjustment (c)	7,643			41,502
Rate case costs (d)	6,535			4,161
Rate adjustment mechanism (e)	14,804			6,207
Other	30,049			29,155
Total regulatory assets	$	245,315		$	247,272
Less current regulatory assets	(32,213		)	(61,645		)
Non-current regulatory assets	$	213,102		$	185,627
Regulatory liabilities
Cost of removal (f)	$	107,988		$	78,013
Rate-base offset (g)	24,984			23,427
Commodity costs adjustment (c)	32,423			10,389
Other	9,952			9,927
Total regulatory liabilities	$	175,347		$	121,756
Less current regulatory liabilities	(44,167		)	(20,590		)
Non-current regulatory liabilities	$	131,180		$	101,166

(a) Environmental remediation

Actual expenditures incurred for the clean-up of certain former gas manufacturing facilities (note 13(b)) are recovered through rates over a period of 7 years and are subject to an annual cap.

(b) Pension and post-employment benefits

As part of certain business acquisitions, the regulators authorized a regulatory asset or liability being set up for the amounts of pension and post-employment benefits that have not yet been recognized in net periodic cost and were presented as AOCI prior to the acquisition. An amount of $32,313 relates to a recent acquisition and was authorized for recognition as an asset by the regulator. Recovery is anticipated to be approved in a final rate order to be received on completion of the next general rate case. The balance is recovered through rates over the future services years of the employees at the time the regulatory asset was set up (an average of 10 years) or consistent with the treatment of OCI under ASC 712 Compensation Non-retirement Post-employment Benefits and ASC 715 Compensation Retirement Benefits before the transfer to regulatory asset occurred.

(c) Commodity costs adjustment

The revenue of the electric and natural gas utilities includes a component which is designed to recover the cost of electricity or natural gas through rates charged to customers. Under deferred energy accounting, to the extent actual natural gas and purchased power costs differ from natural gas and purchased power costs recoverable through current rates, that difference is not recorded on the consolidated statements of operations but rather is deferred and recorded as a regulatory asset or liability on the consolidated balance sheets. These differences are reflected in adjustments to rates and recorded as an adjustment to cost of natural gas or electricity in future periods, subject to regulatory review. Derivatives are often utilized to manage the price risk associated with natural gas purchasing activities in accordance with the expectations of state regulators. The gains and losses associated with these derivatives (note 24(b)(i)) are recoverable through the commodity costs adjustment.

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2015 and 2014

(in thousands of Canadian dollars, except as noted and per share amounts)

7. Regulatory matters (continued)

(d) Rate case costs

The costs to file, prosecute and defend rate case applications are referred to as rate case costs. These costs are capitalized and amortized over the period of rate recovery granted by the regulator.

(e) Rate adjustment mechanism

Revenue for Calpeco Electric System, Peach State Gas System and New England Gas Systems are subject to a revenue decoupling mechanism approved by their respective regulator which require charging approved annual delivery revenue on a systematic basis over the fiscal year. As a result, the difference between delivery revenue calculated based on metered consumption and approved delivery revenue is recorded as a regulatory asset or liability to reflect future recovery or refund, respectively, from customers. In addition, retroactive rate adjustments for services rendered but collected over a period not exceeding 24 months is accrued upon approval of the Final Order.

(f) Cost of removal

The regulatory liability for cost of removal represents amounts that have been collected from ratepayers for costs that are expected to be incurred in the future to retire the utility plant.

(g) Rate-base offset

The regulators imposed a rate-base offset that would reduce the revenue requirement at future rate proceedings. The rate-base offset declines on a straight-line basis over a period of ten years.

As recovery of regulatory assets is subject to regulatory approval, if there were any changes in regulatory positions that indicate recovery is not probable, the related cost would be charged to earnings in the period of such determination. The Company earns carrying charges on the regulatory balances related to commodity cost adjustment and rate case costs.

8. Long-term investments

Long-term investments consist of the following:

	2015		2014
Equity-method investees
50% interest in Odell Wind Project Joint Venture (a)	$	42,287	$	2,267
50% interest in Deerfield Wind Project Joint Venture (b)	2,240		—
Interests in natural gas pipeline developments (c)	5,623		1,063
Other	2,323		3,268
	$	52,473	$	6,598
Available-for-sale investment	$	2,946	$	137
Notes receivable
Development loans (d)	$	96,924	$	17,582
Red Lily Senior loan Tranche 2, interest at 6.31% (e)	11,588		11,588
Red Lily Subordinated loan Tranche 1, interest at 12.5% (e)	6,565		6,565
Other	4,306		3,775
	119,383		39,510
Total long-term investments	174,802		46,245
Less current portion	—		(2,966		)
Total long-term investments	$	174,802	$	43,279

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2015 and 2014

(in thousands of Canadian dollars, except as noted and per share amounts)

8. Long-term investments (continued)

(a)Odell Wind Project Joint Venture

On November 14, 2014, the Company acquired a 50% equity interest in Odell SponsorCo LLC (“Odell SponsorCo”), which indirectly owns a 200 MW construction-stage wind development project (“Odell Wind Project”) in the state of Minnesota. The total construction costs of the Odell Wind Project are estimated to be U.S.$322,766.

The two members each contributed U.S.$1,000 to the capital of Odell SponsorCo on acquisition and another U.S.$23,800 on October 6, 2015. The Company holds an option to acquire the other 50% interest for total contributions, subject to certain adjustments, within 30 days of commencement of operations, which is expected in 2016. The interest capitalized during the year to the investment while the Odell Wind Project is under construction amounts to $4,415 (2014 - nil).

As of December 31, 2015, Odell SponsorCo is considered a VIE namely due to the low level of its equity at that point. The Company is not considered the primary beneficiary of Odell SponsorCo as the two members have joint control and all decisions must be unanimous. As such, the Company is accounting for the joint venture as an equity method investment. The Company’s maximum exposure to loss is $190,840 as of December 31, 2015.

(b) Deerfield Wind Project Joint Venture

On October 19, 2015, the Company acquired a 50% equity interest in Deerfield Wind SponsorCo LLC (“Deerfield SponsorCo”), which indirectly owns a 150 MW construction-stage wind development project (“Deerfield Wind Project”) in the state of Michigan. The total construction costs of the Deerfield Wind Project are estimated to be U.S.$303,000.

Upon the acquisition of the Deerfield Wind Project by Deerfield SponsorCo, the two members each contributed U.S.$1,000 to the capital of Deerfield SponsorCo. Upon execution of third-party construction loan and tax equity documents expected in 2016, each party will contribute another U.S.$18,596 plus accrued interest at 7% to the capital of Deerfield SponsorCo. The Company holds an option to acquire the other 50% interest for total contributions, subject to certain adjustments at any time prior to the date that is 90 days following commencement of operations, which is expected in late 2016. The interest capitalized during the year to the investment while the Deerfield Wind Project is under construction amounts to $94.

As of December 31, 2015, Deerfield SponsorCo is considered a VIE namely due to the low level of its equity at that point. The Company is not considered the primary beneficiary of Deerfield SponsorCo as the two members have joint control and all decisions must be unanimous. As such, the Company is accounting for the joint venture as an equity method investment. The Company’s maximum exposure to loss is $321,472 as of December 31, 2015.

(c) Natural gas pipeline developments

In December 2015, APUC acquired a 4.0% interest in Northeast Supply Pipeline LLC with an option to increase its participation to 10%. Northeast Supply LLC is a new entity undertaking the development, construction and ownership of natural gas transmission pipeline to be constructed between the Bradford and Susquehanna counties in Pennsylvania and Wright, NY.  The project is expected to reach commercial operations by late 2018. The Company assessed that its interest of 4.0% in a limited liability corporation together with the option to increase its participation to 10% provide significant influence. As such, the interest is accounted as an equity method investment.

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2015 and 2014

(in thousands of Canadian dollars, except as noted and per share amounts)

8. Long-term investments (continued)

(c) Natural gas pipeline developments (continued)

In November 2014, APUC acquired a 2.5% interest in Northeast Expansion LLC with an option to increase its participation to 10%. Northeast Expansion LLC is a new entity undertaking the development, construction and ownership of a natural gas transmission pipeline to be constructed between Wright, NY and Dracut, MA.  The project is expected to reach commercial operations by late 2018.  The Company assessed that its interest of 2.5% in a limited liability corporation together with the option to increase its participation to 10% and the commitment from its New Hampshire subsidiary to a firm gas transportation agreement for service on the pipeline facilities provide significant influence. As such, the interest is accounted as an equity method investment.

The total capital investment assuming the Company exercises its right to subscribe for 10% of each pipeline is estimated to be U.S.$520,000. As of December 31, 2015, APUC had invested U.S.$4,063 (2014 - U.S.$375) in the pipeline projects.

(d) Development loans

The Company entered into a committed loan and credit support facility with Odell SponsorCo and Deerfield SponsorCo (collectively, the “Joint Ventures”). During construction, the Company is obligated to provide Joint Ventures with cash advances and credit support (in the form of letters of credit, escrowed cash, or guarantees) in amounts necessary for the continued development and construction of the Joint Ventures’ Wind Projects. The loan bears interest at an annual rate of 7%-8% on outstanding principal amount until commercial operation date and 5% thereafter until maturity date, and the letters of credit are charged an annual fee of 2% on their stated amount. Any loan outstanding to Joint Ventures, to the extent not otherwise repaid earlier, is repayable in cash within 30 days of the fifth anniversary of the commercial operation date.

As of December 31, 2015, the Company had outstanding loans of U.S.$62,751 from Odell SponsorCo and U.S.$7,281 from Deerfield SponsorCo for development costs of the Joint Ventures’ Wind Projects. No interest revenue is accrued on the loans due to insufficient collateral in the Joint Ventures.

As of December 31, 2015, the following credit support was issued by the Company: a U.S.$15,000 letter of credit on behalf of the Odell Wind Project, to the utility under the PPA; a U.S.$1,119 letter of credit on behalf of the the Odell Wind Project pursuant to the generator interconnection agreement; guarantee of the obligations of the Joint Ventures under the wind turbine supply agreements; guarantee of the obligations of the Deerfield Wind Project under the power purchase agreement and decommissioning plan; and, a U.S. $43,238 letter of credit and guarantee of the obligations of Deerfield SponsorCo, to the vendor under the membership interest purchase and contribution agreement. The initial value of the guarantee obligations is recognized under other long-term liabilities and was valued at U.S.$1,147 using a probability weighted discounted cash flow (level 3).

(e) Red Lily I

The Red Lily I Partnership (the “Partnership”) is owned by an independent investor. APUC provides operation and supervision services to the Red Lily I project, a 26.4 MW wind energy facility located in southeastern Saskatchewan.

The Company’s investment in Red Lily I is in the form of participation in a portion of the senior and subordinated debt facilities to the Partnership.

The senior debt facility consists of two tranches. A third-party lender advanced $27,000 of senior debt to the Partnership as Tranche 1. In 2011, APUC advanced $13,000 of senior debt as Tranche 2 to the Partnership and received a pre-payment of $1,412 in 2012. The third-party lender has also advanced $4,000 of senior debt Tranche 2 to the Partnership. The Company’s senior loan Tranche 2 to the Partnership earned interest at the rate of 6.31% and was replaced by subordinated debt Tranche 2 on February 23, 2016 as described below. Both tranches of senior debt are secured by substantially all the assets of the Partnership on a pari passu basis.

The subordinated loan earns an interest rate of 12.5%, and the principal matures in 2036 but is repayable by the Partnership in whole or in part at any time after 2016, without a pre-payment premium. The subordinated loan is secured by substantially all the assets of the Partnership but is subordinated to the senior debt.

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2015 and 2014

(in thousands of Canadian dollars, except as noted and per share amounts)

8. Long-term investments (continued)

(e) Red Lily I (continued)

Subsequent to year-end, on February 23, 2016, a second tranche of subordinated loan for an amount equal to $15,588 was advanced by the Company. The proceeds from this additional subordinated debt were used by Red Lily I to repay Tranche 2 of the Partnership’s senior debt, including the Company’s portion.

In connection with the subordinated debt facility, the Company has an option to subscribe for a 75% equity interest in the Partnership in exchange for the outstanding amount on its Tranche 1 and Tranche 2 subordinated loans, exercisable for a period of 90 days commencing on February 24, 2016.

The above notes are secured by the underlying assets of the respective facilities.

9. Long-term debt

Long-term debt consists of the following:

	2015		2014
Generation Group
$350,000 revolving credit facility, interest rate is equal to bankers’ acceptance or LIBOR plus a variable rate as outlined in the credit facility agreement. The current rate is BA or LIBOR plus 1.45%, maturing July 31, 2019.	$	27,300	$	23,400
Algonquin Power Co.: Senior Unsecured Notes: $200,000 bearing an interest rate of 4.65%, maturing February 15, 2022; $150,000 bearing an interest rate of 4.82%, maturing February 15, 2021;  $135,000 bearing an interest rate of 5.50%, maturing July 25, 2018. The notes have interest only payments, payable semi-annually in arrears.	481,991		481,438
Shady Oaks Wind Facility: Senior Debt: U.S.$76,000 Chinese Development Bank Corporation loan facility, bearing an interest rate of 6 month LIBOR plus 280 basis points. This facility was repaid in May 2015.	—		88,168
Long Sault Hydro Facility: Senior Debt: $34,760 bonds bearing an interest rate of 10.21%, maturing December 31, 2027. The bonds have interest and principal payments, payable monthly in arrears.	34,760		35,997
Chuteford Hydro Facility: Senior Debt: $2,587 bonds bearing an interest rate of 11.55%, maturing April 1, 2020. The bond has principal and interest payments, payable monthly in arrears.	2,587		3,022
Distribution Group
U.S.$200,000 revolving credit facility, interest rate is equal to LIBOR plus a variable rate as outlined in the credit facility agreement. The current rate is LIBOR plus 1.25%, maturing September 30, 2018.	—		23,898
Liberty Utilities Co.: Senior Unsecured Notes: U.S.$ 50,000, bearing an interest rate of 3.51%, maturing July 31, 2017; U.S.$ 25,000, bearing an interest rate of 3.23%, maturing July 31, 2020; U.S.$115,000, bearing an interest rate of 4.49%, maturing August 1, 2022; U.S.$ 15,000, bearing an interest rate of 4.14%, maturing March 13, 2023; U.S.$ 75,000, bearing an interest rate of 3.86%, maturing July 31, 2023; U.S.$ 60,000, bearing an interest rate of 4.89%, maturing July 30, 2027; U.S.$ 25,000, bearing an interest rate of 4.26%, maturing July 31, 2028; U.S.$ 90,000, bearing an interest rate of 4.13%, maturing April 30, 2045; U.S.$ 70,000, bearing an interest rate of 4.13%, maturing July 15, 2045. The notes have interest only payments, payable semi-annually.	721,581		419,876

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2015 and 2014

(in thousands of Canadian dollars, except as noted and per share amounts)

	2015			2014
Calpeco Electric System: Senior Unsecured Notes: U.S.$45,000 bearing an interest rate of 5.19%, maturing December 29, 2020; U.S.$25,000 bearing an interest rate of 5.59%, maturing December 29, 2025. The notes have interest only payments, payable semi-annually in arrears.	96,015			80,368
Liberty Water Co: Senior Unsecured Notes: U.S.$50,000 bearing an interest rate of 5.60% $5,000 matures annually beginning June 20, 2016; $25,000 maturing December 22, 2020.  The note bears interest payments semi-annually in arrears.	68,488			57,301
New England Gas System: First Mortgage Bonds: U.S.$6,500, bearing an interest rate of 9.44%, maturing February 15, 2020; U.S.$7,000, bearing an interest rate of 7.99%, maturing September 15, 2026; U.S.$6,000, bearing an interest rate of 7.24%, maturing December 15, 2027. The notes have interest only payments, payable semi-annually in arrears.	32,130			27,288
Granite State Electric System: Senior Unsecured Notes: U.S.$5,000, bearing an interest rate of 7.37%, maturing November 1, 2023; U.S.$5,000, bearing an interest rate of 7.94%, maturing July 1, 2025; U.S.$5,000, bearing an interest rate of 7.30%, maturing June 15, 2028. The notes have interest only payments, payable semi-annually.	20,730			17,373
LPSCo Water System: 1999 and 2001 IDA bonds bearing interest rates of 5.85% and 6.71%. This facility was repaid in October 2015.	—			12,441
Bella Vista Water System: U.S.$877 Water Infrastructure Financing Authority of Arizona loans bearing interest rates of 6.26% and 6.10%, and maturing March 1, 2020 and December 1, 2017, respectively. The loans have principal and interest payments, payable monthly and quarterly in arrears.	1,213			1,149
	$	1,486,795		$	1,271,719
Less: current portion	(8,945		)	(9,130		)
	$	1,477,850		$	1,262,589

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2015 and 2014

(in thousands of Canadian dollars, except as noted and per share amounts)

9. Long-term debt (continued)

Certain long-term debt issued at a subsidiary level relating to a specific operating facility is secured by the respective facility with no other recourse to the Company. The loans have certain financial covenants, which must be maintained on a quarterly basis. Non-compliance with the covenants could restrict cash distributions/dividends to the Company from the specific facilities.

Effective January 1, 2015, the Company applied ASU 2015-03 (note 2(a)) retrospectively to all prior periods presented in the financial statements. As a result, deferred financing costs of $8,304 as of December 31, 2014 that were previously presented as other assets on the consolidated balance sheets have been reclassified as a deduction from the carrying amount of the related long-term debt in the table above.

Generation Group

On October 30, 2015, the Generation Group entered into a new extendible one-year letter of credit facility agreement.  The new facility expands the group’s available liquidity by providing for issuances of letters of credit up to a maximum of $50,000 and U.S.$30,000.  If the facility is not extended at maturity, cash collateral equal to letters of credit outstanding at that date would be posted by the Company.

On May 12, 2015, the U.S.$76,000 senior debt for the Shady Oaks Wind Facility was repaid.

On December 31, 2014, the U.S.$19,200 senior debt for the Sanger thermal facility was repaid.

On July 31, 2014, the Company increased the credit available under the senior unsecured revolving credit facility to $350,000 from $200,000. The larger revolving credit facility will be used to provide additional liquidity in support of the Generation Group’s development portfolio to be completed over the next three years. The maturity of the revolving credit facility has been extended to July 31, 2018. On May 27, 2015, the Generation Group extended the maturity of its senior unsecured revolving credit facility one year to July 31, 2019 with all other terms remaining the same.

On January 17, 2014, the Company issued $200,000 senior unsecured debentures bearing interest at 4.65% and with a maturity date of February 15, 2022. The debentures were sold at a price of $99.864 per $100.00 principal amount. Interest payments are payable on February 15 and August 15 each year, commencing on February 15, 2014. The Company incurred deferred financing costs of $1,568, which are being amortized to interest expense over the term of the loan using the effective interest rate method. Concurrent with the offering, the Company entered into a cross currency swap, coterminous with the debentures, to economically convert the Canadian dollar denominated offering into U.S. dollars. The Company designated the entire notional amount of the cross currency fixed for fixed interest rate swap and related short-term U.S. dollar payables created by the monthly accruals of the swap settlement as a hedge of the foreign currency exposure of its net investment in the Company’s U.S. operations. The gain or loss related to the fair value changes of the swap and the related foreign currency gains and losses on the U.S. dollar accruals that are designated as, and are effective as, an economic hedge of the net investment in a foreign operation is reported in the same manner as the translation adjustment (in OCI) related to the net investment (note 24(b)(iii)).

Distribution Group

On October 1, 2015, the U.S.$9,800 LPSCo Water System IDA bonds were fully repaid.

On April 30, 2015, the Distribution Group issued U.S.$160,000 of senior unsecured 30-year notes bearing a coupon of 4.13% via a private placement in the U.S. The proceeds of the financing will be used in connection with the acquisition of the Park Water System and for general corporate purposes. The funds were drawn in two tranches: U.S.$90,000 was drawn on closing and U.S.$70,000 was drawn on July 15, 2015.

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2015 and 2014

(in thousands of Canadian dollars, except as noted and per share amounts)

9. Long-term debt (continued)

Corporate

APUC has a senior unsecured revolving credit of U.S.$65,000. subsequent to year end the maturity date of the facility was extended by one year to November 19, 2017. As of December 31, 2015 and 2014, no amounts were outstanding under this revolving credit facility.

Subsequent to year-end, on February 9, 2016, in connection with the acquisition of Empire (note 3 (a)), the Company obtained $2,200,000 (U.S.$1,600,000) in bridge financing commitments from a syndicate of banks. The non-revolving term credit facilities are comprised of a U.S.$1,065,000 debt bridge facility, repayable in full on the first anniversary following its advance, and a U.S.$535,000 equity bridge facility repayable in full on the first anniversary following its advance. On March 1, 2016, upon issuing the Debentures (including the overallotment) (note 25) and receiving the First Instalment, the Company reduced its bridge commitments by $359,950.

Subsequent to year-end, on January, 4, 2016, a subsidiary of APUC entered into a U.S.$235,000 term credit facility with two U.S. banks. The term credit facility is available for acquisitions and general corporate purposes and matures on July 5, 2017.

As of December 31, 2015, the Company had accrued $25,161 in interest expense (2014 - $18,770). Interest expense on the long-term debt in 2015 was $72,213 (2014 - $64,218).

Principal payments due in the next five years and thereafter are as follows: 

	2016		2017		2018		2019		2020		Thereafter		Total
Generation Group	$	1,816	$	2,045	$	137,272	$	30,152	$	2,641	$	375,415	$	549,341
Distribution Group	7,129		76,358		7,135		7,149		147,640		701,371		946,782
Total	$	8,945	$	78,403	$	144,407	$	37,301	$	150,281	$	1,076,786	$	1,496,123

10. Pension and other post-employment benefits

The Company provides defined contribution pension plans to substantially all of its employees. The Company’s contributions for 2015 were $4,132 (2014 - $3,287).

In conjunction with recent utilities acquisitions, the Company assumed defined benefit pension and OPEB plans for qualifying employees in the related acquired businesses. The legacy plans of the electricity and gas utilities are non-contributory defined pension plans covering substantially all employees of the acquired businesses. Benefits are based on each employee’s years of service and compensation. The Company also provides a defined benefit cash balance pension plan covering substantially all its new employees and current employees at its water utilities, under which employees are credited with a percentage of base pay plus a prescribed interest rate credit. The OPEB plans provide health care and life insurance coverage to eligible retired employees. Eligibility is based on age and length of service requirements and, in most cases, retirees must cover a portion of the cost of their coverage.

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2015 and 2014

(in thousands of Canadian dollars, except as noted and per share amounts)

10. Pension and other post-employment benefits (continued)

(a) Net pension and OPEB obligation

The following table sets forth the projected benefit obligations, fair value of plan assets, and funded status of the Company’s plans as of December 31:

	Pension benefits						OPEB
	2015			2014			2015			2014
Change in projected benefit obligation
Projected benefit obligation, beginning of year	$	241,963		$	178,113		$	68,257		$	45,399
Projected benefit obligation assumed from business combination	—			1,022			—			—
Modifications to pension plan	(4,995		)	(560		)	—			—
Service cost	6,663			4,828			3,093			2,022
Interest cost	9,642			8,549			2,914			2,186
Actuarial loss (gain)	(16,098		)	39,704			(8,466		)	14,893
Contributions from retirees	—			—			412			331
Benefits paid	(13,024		)	(8,125		)	(2,447		)	(1,586		)
Loss on foreign exchange	45,231			18,432			12,802			5,012
Projected benefit obligation, end of year	$	269,382		$	241,963		$	76,565		$	68,257
Change in plan assets
Fair value of plan assets, beginning of year	156,990			139,280			14,295			13,395
Actual return (loss) on plan assets	(5,657		)	6,568			20			1,176
Employer contributions	7,975			5,676			3,028			(222		)
Benefits paid	(12,589		)	(7,414		)	(2,036		)	(1,255		)
Gain on foreign exchange	29,453			12,880			2,842			1,201
Fair value of plan assets, end of year	$	176,172		$	156,990		$	18,149		$	14,295
Unfunded status	$	(93,210	)	$	(84,973	)	$	(58,416	)	$	(53,962	)
Amounts recognized in the consolidated balance sheets consists of:
Current liabilities	(470		)	—			(1,062		)	(333		)
Non-current liabilities	(92,740		)	(84,973		)	(57,354		)	(53,629		)
Net amount recognized	$	(93,210	)	$	(84,973	)	$	(58,416	)	$	(53,962	)

The accumulated benefit obligation for the pension plans was $251,932 and $219,007 as of December 31, 2015 and 2014, respectively.

During 2015, the Company permanently froze the accrual of retirement benefits for union participants and most non-union participants under existing plans, effective December 31, 2015 and March 31, 2015, respectively. Subsequent to the effective date, these employees began accruing benefits under the Company’s cash balance plan. The plan amendments resulted in a decrease to the projected benefit obligation of U.S. $3,941 which is recorded as a prior service credit in OCI.

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2015 and 2014

(in thousands of Canadian dollars, except as noted and per share amounts)

10. Pension and other post-employment benefits (continued)

(a) Net pension and OPEB obligation (continued)

The amounts recognized in OCI before tax were as follows: 

	AOCI
	Pension			OPEB
Balance, January 1, 2014	$	(14,385	)	$	(9,083	)
Current year net actuarial gain	43,350			14,338
Current year prior service loss	(563		)	—
Amortization of net actuarial loss	349			641
Balance at December 31, 2014	$	28,751		$	5,896
Current year net actuarial loss	1,505			(7,554		)
Current year prior service credits	(4,864		)	—
Amortization of net actuarial gain	(1,358		)	(680		)
Amortization of prior service credits	457			—
Balance at December 31, 2015	$	24,491		$	(2,338	)

The net actuarial loss for the defined benefit pension plans and OPEB that will be amortized from AOCI into net periodic benefit cost over the next fiscal year are $632 and $88, respectively.

(b) Assumptions

Weighted average assumptions used to determine net benefit cost for 2015 and 2014 were as follows: 

	Pension benefits				OPEB
	2015		2014		2015		2014
Discount rate	3.71	%	4.55	%	3.82	%	4.60	%
Expected return on assets	6.44	%	7.00	%	5.50	%	5.53	%
Rate of compensation increase	3.01	%	2.97	%	N/A		N/A
Health care cost trend rate
Before Age 65					7.00	%	7.63	%
Age 65 and after					7.00	%	7.63	%
Assumed Ultimate Medical Inflation Rate					5.00	%	5.00	%
Year in which Ultimate Rate is reached					2019		2019

Weighted average assumptions used to determine net benefit obligation for 2015 and 2014 were as follows: 

	Pension benefits				OPEB
	2015		2014		2015		2014
Discount rate	4.16	%	3.71	%	4.23	%	3.80	%
Rate of compensation increase	3.00	%	3.01	%	N/A		N/A
Health care cost trend rate
Before Age 65					6.50	%	7.00	%
Age 65 and after					6.50	%	7.00	%
Assumed Ultimate Medical Inflation Rate					4.75	%	5.00	%
Year in which Ultimate Rate is reached					2023		2019

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2015 and 2014

(in thousands of Canadian dollars, except as noted and per share amounts)

10. Pension and other post-employment benefits (continued)

(b) Assumptions (continued)

The mortality assumption for December 31, 2015 was updated to the projected generationally scale MP-2015, adjusted to reflect the ultimate improvement rates in the 2015 Social Security Administration intermediate assumptions.

In selecting an assumed discount rate, the Company uses a modeling process that involves selecting a portfolio of high-quality corporate debt issuances (AA- or better) whose cash flows (via coupons or maturities) match the timing and amount of the Company’s expected future benefit payments. The Company considers the results of this modeling process, as well as overall rates of return on high-quality corporate bonds and changes in such rates over time, to determine its assumed discount rate.

The rate of return assumptions are based on projected long-term market returns for the various asset classes in which the plans are invested, weighted by the target asset allocations.

The effect of a one percent change in the assumed health care cost trend rate (“HCCTR”) for 2015 is as follows: 

	2015
Effect of a 1 percentage point increase in the HCCTR on:
Year-end benefit obligation	$	10,763
Total service and interest cost	1,111
Effect of a 1 percentage point decrease in the HCCTR on:
Year-end benefit obligation	$	(8,687	)
Total service and interest cost	(871		)

(c) Benefit costs

The following table lists the components of net benefit costs for the pension plans and OPEB recorded as part of operating expenses in the consolidated statements of operations. The employee benefit costs related to businesses acquired are recorded in the consolidated statements of operations from the date of acquisition.

	Pension benefits						OPEB
	2015			2014			2015			2014
Service cost	$	6,663		$	4,828		$	3,093		$	2,022
Interest cost	9,642			8,549			2,914			2,186
Expected return on plan assets	(11,989		)	(10,018		)	(713		)	(628		)
Amortization of net actuarial loss (gain)	1,398			(346		)	510			(641		)
Amortization of prior service credits	(471		)	—			—			—
Net benefit cost	$	5,243		$	3,013		$	5,804		$	2,939

(d) Plan assets

The Company’s investment strategy for its pension and post-employment plan assets is to maintain a diversified portfolio of assets with the primary goal of meeting long-term cash requirements as they become due.

The Company’s target asset allocation is as follows:

Asset Class	Target (%)		Range (%)
Equity securities	74	%	49% - 78%
Debt securities	26	%	22% - 51%
Other	—	%	0% - 1%

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2015 and 2014

(in thousands of Canadian dollars, except as noted and per share amounts)

10. Pension and other post-employment benefits (continued)

(d) Plan assets (continued)

The fair values of investments as of December 31, 2015, by asset category, are as follows:

Asset Class	Level 1	Percentage
Equity securities	138,993	72	%
Debt securities	54,542	28	%
Other	787	—	%

As of December 31, 2015, the funds do not hold any material investments in APUC. 

(e) Cash flows

The Company expects to contribute $9,232 to its pension plans and $4,237 to its post-employment benefit plans in 2016.

The expected benefit payments over the next ten years are as follows: 

	2016		2017		2018		2019		2020		2021-2025
Pension plan	$	15,037	$	13,829	$	14,474	$	15,120	$	15,692	$	88,692
OPEB	3,113		3,375		3,584		3,804		4,396		25,720

11.    Mandatorily redeemable Series C preferred shares

APUC has 100 redeemable Series C preferred shares issued and outstanding. Thirty-six of the Series C preferred shares are owned by related parties controlled by executives of the Company. The preferred shares are mandatorily redeemable in 2031 for $53,400 per share (fifty-three thousand and four hundred dollars per share) and have a contractual cumulative cash dividend paid quarterly until the date of redemption based on a prescribed payment schedule indexed in proportion to the increase in CPI over the term of the shares. The Series C preferred shares are convertible into common shares at the option of the holder and the Company, at any time after May 20, 2031 and before June 19, 2031, at a conversion price of $53,400 per share.

As these shares are mandatorily redeemable for cash, they are classified as liabilities in the consolidated financial statements. The Series C preferred shares are accounted for under the effective interest method, resulting in accretion of interest expense over the term of the shares. Dividend payments are recorded as a reduction of the Series C preferred share carrying value.

Estimated dividend payments due in the next five years and dividend and redemption payments thereafter are:
2016	$	979
2017	908
2018	1,068
2019	1,282
2020	1,344
Thereafter to 2031	18,516
Redemption amount	5,340
	29,437
Less amounts representing interest	(10,910		)
	18,527
Less current portion	(979		)
	$	17,548

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2015 and 2014

(in thousands of Canadian dollars, except as noted and per share amounts)

12. Other assets

Other assets consist of the following:

	2015			2014
Restricted cash	$	18,999		$	18,702
Deferred financing costs	3,211			2,428
Other	4,770			4,475
	26,980			25,605
Less current portion	(464		)	—
	$	26,516		$	25,605

13. Other long-term liabilities and deferred credits

Other long-term liabilities consist of the following: 

	2015			2014
Advances in aid of construction (a)	$	92,285		$	81,104
Environmental remediation obligation (b)	71,529			70,072
Asset retirement obligations (c)	17,799			13,884
Customer deposits (d)	15,074			11,713
Deferred income (e)	13,682			13,132
Deferred credits (f)	24,110			19,130
Other	25,277			17,503
	259,756			226,538
Less current portion	(36,621		)	(49,303		)
	$	223,135		$	177,235

(a) Advances in aid of construction

The Company’s regulated utilities have various agreements with real estate development companies (the “developers”) conducting business within the Company’s utility service territories, whereby funds are advanced to the Company by the developers to assist with funding some or all of the costs of the development.

In many instances, developer advances can be subject to refund but the refund is non-interest bearing. Refunds of developer advances are made over periods generally ranging from 10 to 20 years. Advances not refunded within the prescribed period are usually not required to be repaid. After the prescribed period has lapsed, any remaining unpaid balance is transferred to contributions in aid of construction and recorded as an offsetting amount to the cost of property, plant and equipment. In 2015, $4,637 (2014 - $4,608) was transferred from advances in aid of construction to contributions in aid of construction.

(b) Environmental remediation obligation

Prior to their acquisition by the Company, EnergyNorth Gas, Granite State Electric and New England Gas Systems were named as potentially responsible parties for remediation of several sites at which hazardous waste is alleged to have been disposed as a result of historic operations of Manufactured Gas Plants (“MGP”) and related facilities. The Company is currently investigating and remediating, as necessary, those MGP and related sites in accordance with plans submitted to the agency with authority for each of the respective sites.

The Company estimates the remaining undiscounted, unescalated cost of these MGP-related environmental cleanup activities will be $78,495 (2014 - $72,594) which at discount rates ranging from 2.5% to 4.2% represents the recorded accrual of $71,529 as of December 31, 2015 (2014 - $70,072). Approximately $46,929 is expected to be incurred over the next three years with the balance of cash flows to be incurred over the following 29 years.

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2015 and 2014

(in thousands of Canadian dollars, except as noted and per share amounts)

13. Other long-term liabilities and deferred credits (continued)

(b) Environmental remediation obligation (continued)

Changes in the environmental remediation obligation are as follows:

	2015			2014
Opening Balance	$	70,072		$	69,555
Remediation activities	(10,621		)	(12,739		)
Accretion	2,147			2,273
Changes in cash flow estimates	3,171			268
Revision in assumptions	(5,843		)	1,954
Purchase price adjustment	—			2,726
Foreign exchange rate adjustment	12,603			6,035
Closing Balance	$	71,529		$	70,072

By rate orders, the Regulator provided for the recovery of actual expenditures for site investigation and remediation over a period of 7 years and accordingly, as of December 31, 2015, the Company has reflected a regulatory asset of $116,747 (2014 - $102,735) for the MGP and related sites (note 7(a)).

(c) Asset retirement obligations

Asset retirement obligations mainly relate to legal requirements to: (i) remove wind farm facilities upon termination of land leases; (ii) cut (disconnect from the distribution system), purge (cleanup of natural gas and PCB contaminants) and cap gas mains within the gas distribution and transmission system when mains are retired in place, or sections of gas main are removed from the pipeline system; (iii) clean and remove storage tanks containing waste oil and other waste contaminants; and (iv) remove asbestos upon major renovation or demolition of structures and facilities.  During the year, APUC recorded additional asset retirement obligations of $506 (2014 - $2,570) for renewable generation facilities being constructed and accretion expense of $854 (2014 - $527).

(d) Customer deposits

Customer deposits result from the Company’s obligation by state regulators to collect a deposit from customers of its facilities under certain circumstances when services are connected. The deposits are refundable as allowed under the facilities’ regulatory agreement.  

(e) Deferred income

Proceeds received from insurance in advance of repairs, rates collected subject to dispute and other similar proceeds are deferred until they are virtually certain of being realized.

(f) Deferred credits

Deferred credits include deferred tax credits (note 19) of $3,350 (2014 - $19,130).

14. Shareholders’ capital

(a) Common shares

Number of common shares: 

	2015	2014
Common shares, beginning of year	238,149,468	206,348,985
Public offering (i)	14,355,000	29,444,000
Issuance of shares under the dividend reinvestment (iv) and employee share purchase plans ((c)(ii))	3,364,951	2,356,483
Common shares, end of year	255,869,419	238,149,468

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2015 and 2014

(in thousands of Canadian dollars, except as noted and per share amounts)

14. Shareholders’ capital (continued)

(a) Common shares (continued)

Authorized

APUC is authorized to issue an unlimited number of common shares. The holders of the common shares are entitled to dividends if, as and when declared by the Board of Directors (the “Board”); to one vote per share at meetings of the holders of common shares; and upon liquidation, dissolution or winding up of APUC to receive pro rata the remaining property and assets of APUC, subject to the rights of any shares having priority over the common shares.

The Company has a shareholders’ rights plan (the “Rights Plan”) which expires in April 2016. Under the Rights Plan, one right is issued with each issued share of the Company. The rights remain attached to the shares and are not exercisable or separable unless one or more certain specified events occur. If a person or group acting in concert acquires 20 percent or more of the outstanding shares (subject to certain exceptions) of the Company, the rights will entitle the holders thereof (other than the acquiring person or group) to purchase shares at a 50 percent discount from the then current market price. The rights provided under the Rights Plan are not triggered by any person making a “Permitted Bid”, as defined in the Rights Plan.

(i)Public offering

In December 2015, APUC issued 14,355,000 common shares at $10.45 per share pursuant to a public offering for proceeds of $150,010 before issuance costs of $6,735 or $5,023 net of taxes.

In December 2014, APUC issued 10,055,000 common shares at $9.95 per share pursuant to a public offering for proceeds of $100,047, before issuance costs of $4,243 or $3,021 net of taxes.

In September 2014, APUC issued 19,389,000 common shares at $8.90 per share pursuant to a public offering for proceeds of $172,562, before issuance costs of $7,648 or $5,719 net of taxes.

(ii) Subscription receipts

On December 29, 2014, the Company received total proceeds of $77,503 from the issuance to Emera Inc. (“Emera”) of 8,708,170 subscription receipts at a price of $8.90 per share in connection with the Odell SponsorCo investment (note 8(a)). At any time, Emera may elect to convert the subscription receipts for no additional consideration on a one-for-one basis into common shares. In the event that Emera has not elected to convert the subscription receipts by November 14, 2016, they will automatically convert into common shares.

On December 29, 2014, the Company received total proceeds of $33,000 from the issuance to Emera of 3,316,583 subscription receipts at a price of $9.95 per share in connection with the Park Water System acquisition (note 3(b)). At any time, Emera may elect to convert the subscription receipts for no additional consideration on a one-for-one basis into common shares. In the event that Emera has not elected to convert the subscription receipts by December 29, 2016, they will automatically convert into common shares.

(iii) Dividend reinvestment plan

The Company has a common shareholder dividend reinvestment plan, which provides an opportunity for shareholders to reinvest dividends for the purpose of purchasing common shares. Additional common shares acquired through the reinvestment of cash dividends are purchased in the open market or are issued by APUC at a discount of up to 5% from the average market price, all as determined by the Company from time to time. Subsequent to year-end, APUC issued an additional 292,337 common shares under the dividend reinvestment plan.

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2015 and 2014

(in thousands of Canadian dollars, except as noted and per share amounts)

14. Shareholders’ capital (continued)

(b) Preferred shares

APUC is authorized to issue an unlimited number of preferred shares, issuable in one or more series, containing terms and conditions as approved by the Board.

The Company has the following Series A and Series D preferred shares issued and outstanding as at December 31, 2015 and 2014:

Preferred shares	Number of shares	Price per share		Carrying amount
Series A	4,800,000	$	25	$	116,546
Series D	4,000,000	$	25	97,259
				$	213,805

The holders of Series A and Series D preferred shares are entitled to receive fixed cumulative preferential dividends as and when declared by the Board at an annual amount of $1.125 and $1.25 per share, respectively, for each year up to, but excluding December 31, 2018 and March 31, 2019, respectively. The Series A and Series D dividend rate will reset on those dates and every five years thereafter at a rate equal to the then five-year Government of Canada bond yield plus 2.94% and 3.28%, respectively. The Series A and Series D preferred shares are redeemable at $25 per share at the option of the Company on December 31, 2018 and March 31, 2019, respectively, and every fifth year thereafter.

The holders of Series A and Series D preferred shares have the right to convert their shares into cumulative floating rate preferred shares, Series B and Series E, respectively, subject to certain conditions, on December 31, 2018 and March 31, 2019, respectively, and every fifth year thereafter. The Series B and Series E preferred shares will be entitled to receive quarterly floating-rate cumulative dividends, as and when declared by the Board, at a rate equal to the then ninety-day Government of Canada treasury bill yield plus 2.94% and 3.28%, respectively. The holders of Series B and Series E preferred shares will have the right to convert their shares back into Series A and Series D preferred shares on December 31, 2018 and March 31, 2019, respectively and every fifth year thereafter. The Series A, Series B, Series D and Series E preferred shares do not have a fixed maturity date and are not redeemable at the option of the holders thereof.

The Company has 100 redeemable Series C preferred shares issued and outstanding. The mandatorily redeemable Series C preferred shares are recorded as a liability on the consolidated balance sheets (note 11).

(c) Share-based compensation

For the year ended December 31, 2015, APUC recorded $5,330 (2014 - $3,248) in total share-based compensation expense detailed as follows: 

	2015		2014
Share options	$	2,742	$	1,931
Directors deferred share units	404		273
Employee share purchase	158		116
Performance share units	2,026		928
Total share-based compensation	$	5,330	$	3,248

The compensation expense is recorded as part of administrative expenses in the consolidated statements of operations. The portion of share-based compensation costs capitalized as cost of construction is insignificant.

As of December 31, 2015, total unrecognized compensation costs related to non-vested options and PSUs were $3,125 and $1,866, respectively, and are expected to be recognized over a period of 1.74 and 1.63 years, respectively.

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2015 and 2014

(in thousands of Canadian dollars, except as noted and per share amounts)

14. Shareholders’ capital (continued)

(c) Share-based compensation (continued)

(i) Share option plan

The Company’s share option plan (the “Plan”) permits the grant of share options to key officers, directors, employees and selected service providers. The aggregate number of shares that may be reserved for issuance under the Plan must not exceed 10% of the number of shares outstanding at the time the options are granted. The number of shares subject to each option, the option price, the expiration date, the vesting and other terms and conditions relating to each option shall be determined by the Board from time to time. Dividends on the underlying shares do not accumulate during the vesting period. Option holders may elect to surrender any portion of the vested options which is then exercisable in exchange for the “In-the-Money Amount”. In accordance with the Plan, the “In-The-Money Amount” represents the excess, if any, of the market price of a share at such time over the option price, in each case such “In-the-Money Amount” being payable by the Company in cash or shares at the election of the Company. As the Company does not expect to settle these instruments in cash, these options are accounted for as equity awards.

In the case of qualified retirement, the Board may accelerate the vesting of the unvested options then held by the optionee at the Board’s discretion. All vested options may be exercised within ninety days after retirement. In the case of death, the options vest immediately and the period over which the options can be exercised is one year. In the case of disability, options continue to vest and be exercisable in accordance with the terms of the grant and the provisions of the plan. Employees have up to thirty days to exercise vested options upon resignation or termination.

The estimated fair value of options, including the effect of estimated forfeitures, is recognized as expense on a straight-line basis over the options’ vesting periods while ensuring that the cumulative amount of compensation cost recognized at least equals the value of the vested portion of the award at that date. The Company determines the fair value of options granted using the Black-Scholes option-pricing model. The risk-free interest rate is based on the zero-coupon Canada Government bond with a similar term to the expected life of the options at the grant date.  Expected volatility was estimated based on the adjusted historical volatility of the Company’s shares.  The expected life was estimated to equal the contractual life of the options. The dividend yield rate was based upon recent historical dividends paid on APUC shares.

The following assumptions were used in determining the fair value of share options granted: 

	2015			2014
Risk-free interest rate	1.3		%	2.0		%
Expected volatility	38		%	38		%
Expected dividend yield	4.0		%	3.8		%
Expected life	8 years			8 years
Weighted average grant date fair value per option	$	2.45		$	2.00

Share option activity during the years is as follows: 

	Number of awards	Weighted average exercise price		Weighted average remaining contractual term (years)	Aggregate intrinsic value
Balance at January 1, 2014	4,567,129	$	5.70	5.45	$	7,814
Granted	969,998	7.95		8.00	—
Balance at December 31, 2014	5,537,127	$	6.09	4.96	$	19,648
Granted	1,627,525	9.75		8.00	—
Balance at December 31, 2015	7,164,652	$	6.92	4.74	$	28,561
Exercisable at December 31, 2015	4,618,323	$	5.74	3.55	$	23,898

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2015 and 2014

(in thousands of Canadian dollars, except as noted and per share amounts)

14. Shareholders’ capital (continued)

(c) Share-based compensation (continued)

(ii) Employee share purchase plan

Under the Company’s employee share purchase plan (“ESPP”), eligible employees may have a portion of their earnings withheld to be used to purchase the Company’s common shares. The Company will match (a) 20% of the employee contribution amount for the first five thousand dollars per employee contributed annually and 10% of the employee contribution amount for contributions over five thousand dollars up to ten thousand dollars annually, for Canadian employees, and (b) 15% of the employee contribution amount for the first fifteen thousand dollar per employee contributed annually, for U.S. employees. Common shares purchased through the Company match portion shall not be eligible for sale by the participant for a period of one year following the contribution date on which such shares were acquired. At the Company’s option, the common shares may be (i) issued to participants from treasury at the average share price or (ii) acquired on behalf of participants by purchases through the facilities of the TSX by an independent broker. The aggregate number of common shares reserved for issuance from treasury by APUC under the ESPP shall not exceed 2,000,000 common shares.

The Company uses the fair value based method to measure the compensation expense related to the Company’s contribution. For the year ended December 31, 2015, a total of 111,355 common shares (2014 - 93,598) were issued to employees under the ESPP.

(iii) Directors deferred share units

Under the Company’s Deferred Share Unit Plan, non-employee directors of the Company may elect annually to receive all or any portion of their compensation in DSUs in lieu of cash compensation. Directors’ fees are paid on a quarterly basis and at the time of each payment of fees, the applicable amount is converted to DSUs. A DSU has a value equal to one of the Company’s common shares. Dividends accumulate in the DSU account and are converted to DSUs based on the market value of the shares on that date. DSUs cannot be redeemed until the director retires, resigns, or otherwise leaves the Board. The DSUs provide for settlement in cash or shares at the election of the Company. As the Company does not expect to settle these instruments in cash, these options are accounted for as equity awards. As of December 31, 2015, 157,471 (2014 - 110,241) DSUs were outstanding pursuant to the election of the directors to defer a percentage of their director’s fee in the form of DSUs.

(iv) Performance share units

The Company offers a PSU plan to its employees as part of the Company’s long-term incentive program. PSUs are granted annually for three-year overlapping performance cycles. PSUs vest at the end of the three-year cycle and will be calculated based on established performance criteria. At the end of the three-year performance periods, the number of common shares issued can range from 0% to 197.5% of the number of PSUs granted. Dividends accumulating during the vesting period are converted to PSUs based on the market value of the shares on that date and are recorded in equity as the dividends are declared. None of these PSUs have voting rights. Any PSUs not vested at the end of a performance period will expire. The PSUs provide for settlement in cash or shares at the election of the Company. As the Company does not expect to settle these instruments in cash, these options are accounted for as equity awards.

Compensation expense associated with PSUs is recognized rateably over the performance period and assumes that performance goals will be achieved at 100%. If goals met differ, compensation cost recognized is adjusted to reflect the performance conditions achieved.

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2015 and 2014

(in thousands of Canadian dollars, except as noted and per share amounts)

14. Shareholders’ capital (continued)

(c) Share-based compensation (continued)

(iv) Performance share units (continued)

A summary of the PSUs follows: 

	Number of awards		Weighted average grant-date fair value		Weighted average remaining contractual term (years)	Aggregate intrinsic value
Balance at January 1, 2014	66,195		$	6.57	0.62	$	486
Granted	407,962		8.22		3.00	3,333
Exercised	(22,665	)	6.13		—	(185		)
Forfeited	(11,406	)	8.22		—	(93		)
Balance at December 31, 2014	440,086		$	6.57	1.81	$	4,242
Granted, including dividends	212,250		9.72		2.62	—
Exercised	(41,131	)	6.86		—	381
Forfeited	(47,089	)	8.30		—	—
Balance at December 31, 2015	564,116		$	7.59	1.63	$	6,155
Exercisable at December 31, 2015	157,972		$	8.22	—	$	1,723

15. Accumulated other comprehensive income (loss)

AOCI consists of the following balances, net of tax:

	Foreign currency cumulative translation			Unrealized gain on cash flow hedges			Net change on available-for-sale investments			Pension and post-employment actuarial changes			Total
Balance, January 1, 2014	$	(57,471	)	$	11,840		$	—		$	14,221		$	(31,410	)
OCI (loss) before reclassifications	68,938			3,358			519			(35,396		)	37,419
Amounts reclassified	—			5,423			(518		)	(273		)	4,632
Net current period OCI	68,938			8,781			1			(35,669		)	42,051
Acquisition of non-controlling interest	21,029			2,543			—			—			23,572
Balance, December 31, 2014	$	32,496		$	23,164		$	1		$	(21,448	)	$	34,213
OCI before reclassifications	228,861			21,896			(73		)	6,487			257,171
Amounts reclassified	—			(5,731		)	—			1,084			(4,647		)
Net current period OCI	$	228,861		$	16,165		$	(73	)	$	7,571		$	252,524
Balance, December 31, 2015	$	261,357		$	39,329		$	(72	)	$	(13,877	)	$	286,737

Amounts reclassified from AOCI for unrealized gain (loss) on cash flow hedges affected revenue from non-regulated energy sales while those for pension and post-employment actuarial changes affected administrative expenses.

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2015 and 2014

(in thousands of Canadian dollars, except as noted and per share amounts)

16. Dividends

All dividends of the Company are made on a discretionary basis as determined by the Board. The Company declares and pays the dividend on its commons shares in U.S. dollars. Dividends declared in Canadian equivalent dollars during the year were as follows:

	2015				2014
	Dividend		Dividend per share		Dividend		Dividend per share
Common shares	$	124,831	$	0.4867	$	83,097	$	0.3695
Series A preferred shares	$	5,400	$	1.1250	$	5,400	$	1.1250
Series D preferred shares	$	5,000	$	1.2500	$	4,103	$	1.0257

17. Related party transactions

Emera Inc.

A member of the Board of APUC is an executive at Emera. During 2015, the Energy Services Business sold electricity to Maine Public Service Company (“MPS”), and Bangor Hydro (“BH”) subsidiaries of Emera, amounting to U.S.$6,658 (2014 - U.S.$9,821). During 2015, Liberty Utilities purchased natural gas amounting to U.S. $2,292 (2014 - U.S.$3,961) from Emera for its gas utility customers. Both the sale of electricity to Emera and the purchase of natural gas from Emera followed a public tender process the results of which were approved by the regulator in the relevant jurisdiction.

There was U.S.$491 included in accruals in 2015 (2014 - U.S.$nil) related to these transactions at the end of the years.

Equity-method investments

The Company provides administrative services to its equity-method investees and is reimbursed for incurred costs. To that effect, the Company charged its equity-method investees $2,021 (2014 - $189) during the year.

Senior Executives

As at December 31, 2015, $nil (December 31, 2014 - $47) was due from Algonquin Power Systems Ltd., a corporation partially owned by Ian Robertson and Chris Jarratt (collectively “Senior Executives”).

Chartered Aircraft

As part of its normal business practice, APUC has utilized chartered aircraft when it is beneficial to do so and had previously entered into a block time agreement to charter aircraft in which Senior Executives have a partial ownership.

The Company terminated the agreement effective June 28, 2015 and paid a usage shortfall fee of $13. During the year ended December 31, 2015, APUC reimbursed direct costs in connection with the use of the aircraft prior to termination of the block time agreement of $507 (2014 - $721).

Office Facilities

Until the fourth quarter of 2014, APUC had leased its head office facilities from an entity partially owned by Senior Executives. During the fourth quarter of 2014, APUC terminated the related party lease and moved all head office employees into new premises owned by the Company. Base lease costs for the year ended December 31, 2015 were $nil (2014 - $356).

Other

A spouse of one of the Senior Executives was employed to provide market research services to certain subsidiaries of the Company. During the year ended December 31, 2015, APUC paid $22 (2014 - $192) in relation to these services. The spouse is no longer employed by the Company.

Effective December 31, 2013, APUC acquired the shares of Algonquin Power Corporation Inc. (“APC”) which was partially owned by Senior Executives. APC owns the partnership interest in the 18MW Long Sault Hydro Facility. A final post-closing adjustment related to the transaction is expected to be settled in 2016.

The above related party transactions have been recorded at the exchange amounts agreed to by the parties to the transactions.

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2015 and 2014

(in thousands of Canadian dollars, except as noted and per share amounts)

18. Non-controlling interests

Net loss attributable to non-controlling interests consists of the following:

	2015			2014
Net earnings attributable to Class B partnership units of Wind Portfolio SponsorCo (i)	$	—		$	3,484
Net loss attributable to Class A partnership units (ii)	(33,942		)	(27,199		)
Other net earnings attributable to non-controlling interests	1,966			1,529
Total net loss attributable to non-controlling interests	$	(31,976	)	$	(22,186	)

(i) On March 31, 2014, the Company acquired the remaining Class B partnership units of Wind Portfolio SponsorCo from the non-controlling interest holder. As a result of the transaction, the Company now owns 100% of Wind Portfolio SponsorCo’s Class B partnership units (note 3(h)).

(ii) The non-controlling Class A membership equity investors (“Class A partnership units”) in the Senate, Minonk and Sandy Ridge wind facilities and, beginning December 31, 2014, the Bakersfield Solar facility are entitled to allocations of earnings, tax attributes and cash flows in accordance with contractual agreements. The share of earnings attributable to the non-controlling interest holders in these subsidiaries is calculated using the HLBV method of accounting as described in note 1(q).

19. Income taxes

The provision for income taxes in the consolidated statements of operations represents an effective tax rate different than the Canadian enacted statutory rate of 26.5% (2014 - 26.5%). The differences are as follows:

	2015			2014
Expected income tax expense at Canadian statutory rate	$	34,516		$	19,199
Increase (decrease) resulting from:
Recognition of deferred credit	(2,448		)	(5,763		)
Effect of differences in tax rates on transactions in and within foreign jurisdictions and change in tax rates	(3,855		)	(1,677		)
Non-taxable corporate dividend	(3,311		)	(2,618		)
Non-controlling interests share of income	12,511			8,824
Production tax credit	(254		)	(339		)
Allowance for equity funds used during construction	(935		)	(746		)
State taxes	733			604
Adjustment relating to prior periods	2,431			—
CRA Settlement	2,709			—
Other	1,616			(677		)
Income tax expense	$	43,713		$	16,807

For the years ended December 31, 2015 and 2014, earnings from continuing operations before income taxes consist of the following:

	2015		2014
Canadian operations	$	28,481	$	11,930
U.S. operations	101,768		60,519
	$	130,249	$	72,449

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2015 and 2014

(in thousands of Canadian dollars, except as noted and per share amounts)

19. Income taxes (continued)

Income tax expense (recovery) attributable to income (loss) consists of: 

	Current			Deferred			Total
Year ended December 31, 2015
Canada	$	5,272		$	1,959		$	7,231
United States	2,038			34,444			36,482
	$	7,310		$	36,403		$	43,713
Year ended December 31, 2014
Canada	$	5,660		$	(3,538	)	$	2,122
United States	(1,986		)	16,671			14,685
	$	3,674		$	13,133		$	16,807

The tax effect of temporary differences between the financial statement carrying amounts of assets and liabilities and their respective tax bases that give rise to significant portions of the deferred tax assets and deferred tax liabilities as of December 31, 2015 and 2014 are presented below:

	2015			2014
Deferred tax assets:
Non-capital loss, investment tax credits, currently non-deductible interest expenses, and financing costs	$	396,727		$	319,056
Pension and OPEB	57,969			54,458
Acquisition-related costs	6,035			5,168
Environmental obligation	28,230			28,555
Production tax credit	3,027			2,098
Reserves not currently deductible	2,503			2,315
Other	4,970			3,988
Total deferred income tax assets	499,461			415,638
Less valuation allowance	(17,478		)	(15,534		)
Total deferred tax assets	481,983			400,104
Deferred tax liabilities:
Property, plant and equipment	(544,616		)	(387,931		)
Intangible assets	(2,760		)	(2,752		)
Outside basis in partnership	(32,221		)	(15,194		)
Regulatory accounts	(28,270		)	(49,399		)
Financial derivatives	(31,806		)	(15,013		)
Total deferred tax liabilities	(639,673		)	(470,289		)
Net deferred tax liabilities	$	(157,690	)	$	(70,185	)
Consolidated Balance Sheets Classification:
Deferred tax assets	$	18,109		$	64,275
Deferred tax liabilities	(175,799		)	$	(134,460	)
Net deferred tax liabilities	$	(157,690	)	$	(70,185	)

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2015 and 2014

(in thousands of Canadian dollars, except as noted and per share amounts)

19. Income taxes (continued)

The valuation allowance for deferred tax assets as at December 31, 2015 was $17,478 (2014 - $15,534). The valuation allowance primarily relates to operating losses that, in the judgment of management, are not more likely than not to be realized. In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities (including the impact of available carryback and carryforward periods), projected future taxable income, and tax-planning strategies in making this assessment.

As of December 31, 2015, the Company had non-capital losses carried forward available to reduce future year’s taxable income, which expire as follows: 

Year of expiry	Non-capital loss carryforwards
2016	$	—
2017 and onwards	967,499
	$	967,499

On June 26, 2015, the Company entered into an agreement with the Canada Revenue Agency (“CRA”) regarding a CRA’s proposal to reassess APUC’s 2009 through 2013 income tax filings in relation to a unit exchange transaction that occurred on October 27, 2009. The agreement resulted in a $16,042 reduction in the APUC’s deferred tax assets and a proportional reduction of $13,333 in its deferred credits (note 13(f)). Consequently, the Company’s results for 2015 reflect a $2,709 net non-cash charge to deferred income tax expense.

The Company has provided for deferred income taxes for the estimated tax cost of distributed earnings of its subsidiaries. Deferred income taxes have not been provided on approximately $64,678 of undistributed earnings of certain foreign subsidiaries, as the Company has concluded that such earnings are indefinitely reinvested and should not give rise to additional tax liabilities. A determination of the amount of the unrecognized tax liability relating to the remittance of such undistributed earnings is not practicable.

20. Basic and diluted net earnings per share

Basic and diluted earnings per share have been calculated on the basis of net earnings attributable to the common shareholders of the Company and the weighted average number of common shares and subscription receipts outstanding (note 14 (a)(ii)). Diluted net earnings per share is computed using the weighted-average number of common shares, subscription receipts outstanding, additional shares issued subsequent to year-end under the dividend reinvestment plan, PSUs and DSUs outstanding during the year and, if dilutive, potential incremental common shares resulting from the application of the treasury stock method to outstanding share options.

The reconciliation of the net earnings and the weighted average shares used in the computation of basic and diluted earnings per share are as follows:

	2015			2014
Net earnings attributable to shareholders of APUC	$	117,480		$	75,701
Series A Preferred shares dividend	5,400			5,400
Series D Preferred shares dividend	5,000			4,103
Net earnings attributable to common shareholders of APUC	$	107,080		$	66,198
Discontinued operations	(1,032		)	(2,127		)
Net earnings attributable to common shareholders of APUC from continuing operations – Basic and Diluted	$	108,112		$	68,325
Weighted average number of shares
Basic	253,172,088			213,953,870
Effect of dilutive securities	3,344,632			2,387,722
Diluted	256,516,720			216,341,592

The shares potentially issuable as a result of 1,627,525 share options (2014 - 1,786,401) are excluded from this calculation as they are anti-dilutive.

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2015 and 2014

(in thousands of Canadian dollars, except as noted and per share amounts)

21. Segmented information

The Company’s management’s reporting structure is aligned under three business units: Generation, Transmission and Distribution. During the fourth quarter, Management determined that each business unit represents a reporting segment. The comparative information for 2014 has been reclassified to conform with the composition of the reporting segments presented in the current year.

Generation, owns or has interests in hydroelectric, solar, wind power facilities and co-generation. Distribution operates electric, natural gas and water distribution utilities. Finally, Transmission invests in rate regulated electric transmission and natural gas pipeline systems. The Transmission segment includes the equity method investment in the Natural Gas Pipeline Development (note 8(c)) which is not yet significant and as a result is not presented separately in the tables below but grouped within Corporate.

For purposes of evaluating divisional performance, the Company allocates the realized portion of any gains or losses on financial instruments to specific divisions. The unrealized portion of any gains or losses on derivative instruments not designated in a hedging relationship is not considered in management’s evaluation of divisional performance and is therefore allocated and reported in the corporate segment. The results of operations and assets for these segments are reflected in the tables below.

	Year ended December 31, 2015
	Generation			Distribution			Corporate			Total
Revenue	$	244,751		$	783,104		$	—		$	1,027,855
Fuel and power purchased	27,990			348,883			—			376,873
Net revenue	216,761			434,221			—			650,982
Operating expenses	63,601			213,750			1,210			278,561
Administrative expenses	10,822			21,570			8,283			40,675
Depreciation and amortization	67,293			82,513			—			149,806
Gain on foreign exchange	—			—			(2,631		)	(2,631		)
Operating income (loss) from continuing operations	75,045			116,388			(6,862		)	184,571
Interest expense	29,395			34,971			1,627			65,993
Interest, dividend, equity and other income	(1,154		)	(3,974		)	(3,967		)	(9,095		)
Other expenses (gain)	(5,623		)	391			2,656			(2,576		)
Earnings (loss) before income taxes	$	52,427		$	85,000		$	(7,178	)	$	130,249
Property, plant and equipment	$	1,895,617		$	1,914,980		$	63,087		$	3,873,684
Equity-method investees	44,638			769			7,066			52,473
Total assets	2,345,905			2,532,894			112,926			4,991,725
Capital expenditures	55,992			141,445			6,758			204,195

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2015 and 2014

(in thousands of Canadian dollars, except as noted and per share amounts)

21. Segmented information (continued)

	Year ended December 31, 2014
	Generation			Distribution			Corporate			Total
Revenue	$	218,765		$	722,849		$	—		$	941,614
Fuel and power purchased	39,264			381,622			—			420,886
Net revenue	179,501			341,227			—			520,728
Operating expenses	55,482			178,248			308			234,038
Administrative expenses	13,457			19,947			1,288			34,692
Depreciation and amortization	58,248			53,671			2,128			114,047
Gain on foreign exchange	—			—			(1,112		)	(1,112		)
	52,314			89,361			(2,612		)	139,063
Interest expense	33,868			27,139			1,411			62,418
Interest, dividend and other income	(1,187		)	(3,369		)	(3,202		)	(7,758		)
Other expense (gain)	48			300			11,606			11,954
Earnings (loss) before income taxes	$	19,585		$	65,291		$	(12,427	)	$	72,449
Property, plant and equipment	$	1,687,465		$	1,531,166		$	59,791		$	3,278,422
Equity-method investees	3,520			500			2,578			6,598
Total assets	1,896,265			2,098,244			108,339			4,102,848
Capital expenditures	201,063			176,849			54,461			432,373

The majority of non-regulated energy sales are earned from contracts with large public utilities. The following utilities contributed more than 10% of these total revenues in either 2015 or 2014: Hydro Québec 13% (2014 - 11%); Manitoba Hydro 13% (2014 - 13%); PJM 14% (2014 - 10%); and ComEd 11% (2014 - 10%). The Company has mitigated its credit risk to the extent possible by selling energy to large utilities in various North American locations.

APUC operates in the independent power and utility industries in both Canada and the United States. Information on operations by geographic area is as follows:

	2015		2014
Revenue
Canada	$	86,977	$	92,267
United States	940,878		849,347
	$	1,027,855	$	941,614
Property, plant and equipment
Canada	$	592,598	$	590,580
United States	3,281,086		2,687,842
	$	3,873,684	$	3,278,422
Intangible assets
Canada	$	40,186	$	25,601
United States	37,777		28,410
	$	77,963	$	54,011

Revenue is attributed to the two countries based on the location of the underlying generating and utility facilities.

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2015 and 2014

(in thousands of Canadian dollars, except as noted and per share amounts)

22. Commitments and contingencies

(a) Contingencies

APUC and its subsidiaries are involved in various claims and litigation arising out of the ordinary course and conduct of its business. Although such matters cannot be predicted with certainty, management does not consider APUC’s exposure to such litigation to be material to these financial statements, with the exception of those matters described below. Accruals for any contingencies related to these items are recorded in the consolidated financial statements at the time it is concluded that its occurrence is probable and the related liability is estimable.

On October 21, 2011, the Quebec Court of Appeal ordered a subsidiary of APUC to pay approximately $5,400 (including interest) to the Government of Quebec relating to water lease payments that the APUC subsidiary has been paying to the St. Lawrence Seaway Management Corporation (“Seaway Management”) under its water lease with Seaway Management in prior years.

The water lease with Seaway Management contains an indemnification clause which management believes mitigates this claim and management intends to vigorously defend its position.  As a result, the probability of loss, if any, and its quantification cannot be estimated at this time but could range from $nil to $6,800. In 2012, the Company paid an amount of $1,884 to the Government of Quebec in relation to the early years covered by the claim in order to mitigate the impact of accruing interests on any amount ultimately determined to be payable or recoverable.

(b) Commitments

In addition to the commitments related to the proposed acquisitions and development projects disclosed in notes 3, 8 and 25, the following significant commitments exist as of December 31, 2015.

As a result of the dam safety legislation passed in Quebec (Bill C-93), APUC has completed technical assessments on its hydroelectric facility dams owned or leased within the Province of Quebec.  The assessments have identified a number of remedial measures required to meet the new safety standards. APUC currently estimates further capital expenditures of approximately $8,000 over a period of 4 years related to compliance with the legislation.

APUC has outstanding purchase commitments for power purchases, gas delivery, service and supply, service agreements, capital project commitments and operating leases. Detailed below are estimates of future commitments under these arrangements: 

	Year 1		Year 2		Year 3		Year 4		Year 5		Thereafter		Total
Power purchase (i)	$	82,403	$	52,644	$	55,599	$	59,165	$	59,791	$	—	$	309,602
Gas supply and service agreements (ii)	66,264		46,673		36,621		35,482		32,070		82,509		299,619
Service agreements	38,335		38,151		35,019		35,734		35,955		518,193		701,387
Capital projects	35,842		7,571		71		71		71		18		43,644
Operating leases	5,863		5,319		4,866		4,754		4,793		106,210		131,805
Total	$	228,707	$	150,358	$	132,176	$	135,206	$	132,680	$	706,930	$	1,486,057

(i) Power purchase: APUC’s electric distribution facilities have commitments to purchase physical quantities of power for load serving requirements. The commitment amounts included in the table above are based on market prices as of December 31, 2015. However, the effects of purchased power unit cost adjustments are mitigated through a purchased power rate-adjustment mechanism.

(ii) Gas supply and service agreements: APUC’s gas distribution facilities and thermal generation facilities have commitments to purchase physical quantities of natural gas under contracts for purposes of load serving requirements and of generating power.

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2015 and 2014

(in thousands of Canadian dollars, except as noted and per share amounts)

23. Non-cash operating items

The changes in non-cash operating items consist of the following:

	2015			2014
Accounts receivable	$	6,715		$	(23,640	)
Natural gas in storage	3,049			(5,942		)
Supplies and consumable inventory	(2,968		)	(3,861		)
Income taxes receivable	(2,529		)	(189		)
Prepaid expenses	(7,833		)	827
Accounts payable	(18,261		)	54,299
Accrued liabilities	(28,495		)	32,520
Current income tax liability	1,820			(1,527		)
Net regulatory assets and liabilities	37,353			(54,277		)
	$	(11,149	)	$	(1,790	)

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2015 and 2014

(in thousands of Canadian dollars, except as noted and per share amounts)

24. Financial instruments

(a) Fair value of financial instruments

2015	Carrying amount		Fair Value		Level 1		Level 2		Level 3
Notes receivable	$	119,383	$	126,468	$	—	$	126,468	$	—
Derivative financial instruments:
Energy contracts designated as a cash flow hedge	88,357		88,357		—		—		88,357
Commodity contracts for regulated operations	4		4		—		4		—
Total derivative financial instruments	88,361		88,361		—		4		88,357
Total financial assets	$	207,744	$	214,829	$	—	$	126,472	$	88,357
Long-term debt	$	1,486,795	$	1,547,346	$	511,829	$	1,035,517	$	—
Preferred shares, Series C	18,527		17,303		—		17,303		—
Derivative financial instruments:
Energy contracts designated as a cash flow hedge	446		446		—		—		446
Cross-currency swap designated as a net investment hedge	101,559		101,559		—		101,559		—
Interest rate swap designated as a hedge	9,659		9,659		—		9,659		—
Currency forward contract not designated as a hedge	1,918		1,918		—		1,918		—
Commodity contracts for regulated operations	1,676		1,676		—		1,676		—
Total derivative financial instruments	115,258		115,258		—		114,812		446
Total financial liabilities	$	1,620,580	$	1,679,907	$	511,829	$	1,167,632	$	446

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2015 and 2014

(in thousands of Canadian dollars, except as noted and per share amounts)

24. Financial instruments (continued)

(a)Fair value of financial instruments (continued)

2014	Carrying amount		Fair Value		Level 1		Level 2		Level 3
Notes receivable	$	39,510	$	41,339	$	—	$	41,339	$	—
Derivative financial instruments:
Energy contracts designated as a cash flow hedge	41,966		41,966		—		—		41,966
Energy contracts not designated as a cash flow hedge	504		504		—		—		504
Total derivative financial instruments	42,470		42,470		—		—		42,470
Total financial assets	$	81,980	$	83,809	$	—	$	41,339	$	42,470
Long-term debt	$	1,271,719	$	1,363,934	$	520,142	$	843,792	$	—
Preferred shares, Series C	18,693		18,209		—		18,209		—
Derivative financial instruments:
Cross-currency swap designated as a net investment hedge	36,276		36,276		—		36,276		—
Interest rate swaps designated as a hedge	4,684		4,684		—		4,684		—
Interest rate swaps not designated as a hedge	1,383		1,383		—		1,383		—
Commodity contracts for regulated operations	2,928		2,928		—		2,928		—
Total derivative financial instruments	45,271		45,271		—		45,271		—
Total financial liabilities	$	1,335,683	$	1,427,414	$	520,142	$	907,272	$	—

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2015 and 2014

(in thousands of Canadian dollars, except as noted and per share amounts)

24. Financial instruments (continued)

(a) Fair value of financial instruments (continued)

The Company has determined that the carrying value of its short-term financial assets and liabilities approximates fair value as of December 31, 2015 and 2014 due to the short-term maturity of these instruments.

Notes receivable fair values (level 2) have been determined using a discounted cash flow method, using estimated current market rates for similar instruments adjusted for estimated credit risk as determined by management. 

The Company’s level 2 fair value of long-term debt at fixed interest rates and Series C preferred shares has been determined using a discounted cash flow method and current interest rates.

The Company’s level 2 fair value derivative instruments primarily consist of swaps, options and forward physical deals where market data for pricing inputs are observable. Level 2 pricing inputs are obtained from various market indices and utilize discounting based on quoted interest rate curves which are observable in the marketplace.

The Company’s level 3 instruments consist of energy contracts for electricity sales. The significant unobservable inputs used in the fair value measurement of energy contracts are the internally developed forward market prices ranging from $18.39 to $138.3 with a weighted average of $39.98 as of December 31, 2015.  The processes and methods of measurement are developed using the market knowledge of the trading operations within the Company and are derived from observable energy curves adjusted to reflect the illiquid market of the hedges and, in some cases, the variability in deliverable energy.  Significant increases (decreases) in any of these inputs in isolation would result in a significantly lower (higher) fair value measurement. The change in the fair value of the energy contracts is detailed in notes 24(b)(ii) and 24(b)(iv).

Fair value estimates are made at a specific point in time, using available information about the financial instrument. These estimates are subjective in nature and often cannot be determined with precision.

The Company’s accounting policy is to recognize transfers between levels of the fair value hierarchy on the date of the event or change in circumstances that caused the transfer. There was no transfer into or out of level 1, level 2 or level 3 during the years ended December 31, 2015 and 2014.

(b) Derivative instruments

Derivative instruments are recognized on the consolidated balance sheets as either assets or liabilities and measured at fair value at each reporting period.

(i) Commodity derivatives – regulated accounting

The Company uses derivative financial instruments to reduce the cash flow variability associated with the purchase price for a portion of future natural gas purchases associated with its regulated gas service territories. The Company’s strategy is to minimize fluctuations in gas sale prices to regulated customers.

The following are commodity volumes, in dekatherms (“dths”) associated with the above derivative contracts:

	2015
Financial contracts: Gas swaps	1,086,228
Gas options	412,369
	1,498,597

The accounting for these derivative instruments is subject to guidance for rate-regulated enterprises. Therefore, the fair value of these derivatives is recorded as current or long-term assets and liabilities, with offsetting positions recorded as regulatory assets and regulatory liabilities in the consolidated balance sheets. Gains or losses on the settlement of these contracts are included in the calculation of deferred gas costs (note 7(c)). As a result, the changes in fair value of these natural gas derivative contracts and their offsetting adjustment to regulatory assets and liabilities had no earnings impact.

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2015 and 2014

(in thousands of Canadian dollars, except as noted and per share amounts)

24. Financial instruments (continued)

(b) Derivative instruments (continued)

(i) Commodity derivatives – regulated accounting (continued)

The following table presents the impact of the change in the fair value of the Company’s natural gas derivative contracts had on the consolidated balance sheets: 

		2015			2014
Regulatory assets:
Gas swap contracts	U.S.	$	1,058	U.S.	$	2,178
Gas option contracts	U.S.	$	154	U.S.	$	346
Regulatory liabilities:
Gas swap contracts	U.S.	$	3	U.S.	$	—
Gas option contracts	U.S.	$	—	U.S.	$	—

(ii) Cash flow hedges

The Company reduces the price risk on the expected future sale of power generation at Sandy Ridge, Senate and Minonk Wind Facilities and at one of its hydro facilities no longer subject to a power purchase agreement by entering into the following long-term energy derivative contracts. 

Notional quantity (MW-hrs)	Expiry	Receive average prices (per MW-hr)		Pay floating price (per MW-hr)
49,135	December 2016	$	68.56	AESO
801,098	December 2022	U.S. $	42.81	PJM Western HUB
3,419,634	December 2022	U.S. $	30.25	NI HUB
3,997,509	December 2027	U.S. $	36.46	ERCOT North HUB

As of December 31, 2015, an amount receivable under the derivatives for Sandy Ridge, Senate and Minonk Wind Facilities of $4,882 (2014 - $156) was held as collateral by the counterparty.

On November 14, 2014, the Company entered into a 10-year forward-starting interest rate swap beginning on July 25, 2018 in order to reduce the interest rate risk related to the probable issuance on that date of a 10-year $135,000 bond. The change in fair value resulted in a loss of $4,974 for the year ended December 31, 2015 (2014 - loss of $4,684), which is recorded in OCI.

The following table summarizes OCI attributable to derivative financial instruments designated as a cash flow hedge: 

	2015			2014
Effective portion of cash flow hedge, loss (gain)	$	21,932		$	(2,592	)
Amortization of cash flow hedge	(36		)	(32		)
Loss (gain) reclassified from AOCI	(5,731		)	5,423
	$	16,165		$	2,799
Less non-controlling interest	—			5,982
OCI attributable to shareholders of APUC	$	16,165		$	8,781

The Company expects $14,975 of unrealized gains currently in AOCI to be reclassified into non-regulated energy sales within the next twelve months, as the underlying hedged transactions settle.

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2015 and 2014

(in thousands of Canadian dollars, except as noted and per share amounts)

24. Financial instruments (continued)

(b) Derivative instruments (continued)

(iii) Foreign exchange hedge of net investment in foreign operation

The Company is exposed to currency fluctuations from its U.S. based operations. APUC manages this risk primarily through the use of natural hedges by using U.S. long-term debt to finance its U.S. operations and a combination of foreign exchange forward contracts and spot purchases. APUC only enters into foreign exchange forward contracts with major Canadian financial institutions having a credit rating of A or better, thus reducing credit risk on these forward contracts.

The Company designates the amounts drawn on the Generation Group’s revolving credit facility denominated in U.S. dollars in excess of the principal amount on the USD loans receivable from Odell and Deerfield Wind SponsorCo as a hedge of the foreign currency exposure of its net investment in the Generation Group’s U.S. operations. The related foreign currency transaction gain or loss designated as, and effective as, a hedge of the net investment in a foreign operation are reported in the same manner as the translation adjustment (in OCI) related to the net investment. A foreign currency loss of nil for the year ended December 31, 2015 (2014 - $2,727) was recorded in OCI.

Concurrent with its $150,000 and $200,000 debenture offerings in December 2012 and January 2014, respectively, the Company entered into cross currency swaps, coterminous with the debentures, to effectively convert the Canadian dollar denominated offering into U.S. dollars. The Company designated the entire notional amount of the cross currency fixed-for-fixed interest rate swap and related short-term U.S. dollar payables created by the monthly accruals of the swap settlement as a hedge of the foreign currency exposure of its net investment in the Generation Group’s U.S. operations. The gain or loss related to the fair value changes of the swap and the related foreign currency gains and losses on the U.S. dollar accruals that are designated as, and are effective as, a hedge of the net investment in a foreign operation are reported in the same manner as the translation adjustment (in OCI) related to the net investment. A loss of $68,195 (2014 - loss of $28,537) was recorded in OCI in 2015.

(iv) Other derivatives

The Company provides energy requirements to various customers under contracts at fixed rates. While the production from the Tinker Hydroelectric Facility are expected to provide a portion of the energy required to service these customers, APUC anticipates having to purchase a portion of its energy requirements at the ISO NE spot rates to supplement self-generated energy.

This risk is mitigated though the use of short-term financial forward energy purchase contracts which are classified as derivative instruments. The electricity derivative contracts are net settled fixed-for-floating swaps whereby APUC pays a fixed price and receives the floating or indexed price on a notional quantity of energy over the remainder of the contract term at an average rate, as per the following table. These contracts are not accounted for as hedges and changes in fair value are recorded in earnings as they occur.

The Company is exposed to interest rate fluctuations related to certain of its floating rate debt obligation, including certain project specific debt and its revolving credit facilities, its interest rate swaps as well as interest earned on its cash on hand. The Company currently hedges some of that risk (note 24(b)(ii)).

The Company was party to an interest rate swap whereby the Company paid a fixed interest rate of 4.47% on a notional amount of $58,791 and received floating interest at 90 day CDOR. The swap expired on September 2015. As of December 31, 2014, the estimated fair value of the interest rate swap was a liability of $1,383.  This interest rate swap was not accounted for as a hedge.

The Company is exposed to foreign exchange fluctuations related to U.S dollar denominated development loans from projects accounted for as equity investments (note 8(d)). This risk is mitigated through the use of a currency forward contract to sell U.S.$63,400 for $85,812 on April 30, 2016. As of December 31, 2015, the estimated fair value of the instrument was a liability of $1,918. This currency forward contract was not accounted for as a hedge.

For derivatives that are not designated as hedges and for the ineffective portion of gains and losses on derivatives that are accounted for as hedges, the changes in the fair value are immediately recognized in earnings.

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2015 and 2014

(in thousands of Canadian dollars, except as noted and per share amounts)

24. Financial instruments (continued)

(b) Derivative instruments (continued)

(iv) Other derivatives (continued)

The effects on the consolidated statements of operations of derivative financial instruments not designated as hedges consist of the following:

	2015			2014
Change in unrealized loss (gain) on derivative financial instruments:
Interest rate swaps	$	(1,383	)	$	(1,797	)
Energy derivative contracts	886			3,386
Currency forward contract	1,918			—
Total change in unrealized loss (gain) on derivative financial instruments	$	1,421		$	1,589
Realized loss (gain) on derivative financial instruments:
Interest rate swaps	1,498			1,962
Energy derivative contracts	(579		)	(3,627		)
Total realized loss (gain) on derivative financial instruments	$	919		$	(1,665	)
Loss (gain) on derivative financial instruments not accounted for as hedges	2,340			(76		)
Ineffective portion of derivative financial instruments accounted for as hedges	(2,610		)	1,451
	$	(270	)	$	1,375
Amounts recognized in the consolidated statements of operations consist of:
Loss (gain) on derivative financial instruments	$	(2,188	)	$	1,375
Loss on foreign exchange	$	1,918		$	—
	$	(270	)	$	1,375

(c) Risk management

In the normal course of business, the Company is exposed to financial risks that potentially impact its operating results. The Company employs risk management strategies with a view of mitigating these risks to the extent possible on a cost effective basis. Derivative financial instruments are used to manage certain exposures to fluctuations in exchange rates, interest rates and commodity prices. The Company does not enter into derivative financial agreements for speculative purposes.

This note provides disclosures relating to the nature and extent of the Company’s exposure to risks arising from financial instruments, including credit risk and liquidity risk, and how the Company manages those risks.

Credit risk

Credit risk is the risk of an unexpected loss if a customer or counterparty to a financial instrument fails to meet its contractual obligations. The Company’s financial instruments that are exposed to concentrations of credit risk are primarily cash and cash equivalents, accounts receivable, notes receivable and derivative instruments. The Company limits its exposure to credit risk with respect to cash equivalents by ensuring available cash is deposited with its senior lenders all of which have a credit rating of A or better. The Company does not consider the risk associated with the Generation Group accounts receivable to be significant as over 80% of revenue from power generation is earned from large utility customers having a credit rating of BBB or better, and revenue is generally invoiced and collected within 45 days.

The remaining revenue is primarily earned by the Distribution Group which consists of water and wastewater, electric and gas utilities in the United States. In this regard, the credit risk related to Distribution Group accounts receivable balances of U.S.$91,308 is spread over thousands of customers. The Company has processes in place to monitor and evaluate this risk on an ongoing basis including background credit checks and security deposits from new customers. In addition, the state regulators of the Distribution Group allow for a reasonable bad debt expense to be incorporated in the rates and therefore recovered from rate payers.

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2015 and 2014

(in thousands of Canadian dollars, except as noted and per share amounts)

24. Financial instruments (continued)

(c) Risk management (continued)

Credit risk (continued)

As of December 31, 2015, the Company’s maximum exposure to credit risk for these financial instruments was as follows: 

	December 31, 2015
	Canadian $		US $
Cash and cash equivalents and restricted cash	$	39,972	$	74,696
Accounts receivable	15,016		129,791
Allowance for doubtful accounts			(5,756		)
Notes receivable	19,664		72,052
	$	74,652	$	270,783

In addition, the Company continuously monitors the creditworthiness of the counterparties to its foreign exchange, interest rate, and energy derivative contracts prior to settlement, and assesses each counterparty’s ability to perform on the transactions set forth in the contracts. The counterparties consist primarily of financial institutions. This concentration of counterparties may impact the Company’s overall exposure to credit risk, either positively or negatively, in that the counterparties may be similarly affected by changes in economic, regulatory or other conditions.

Liquidity risk

Liquidity risk is the risk that the Company will not be able to meet its financial obligations as they fall due. The Company’s approach to managing liquidity risk is to ensure, to the extent possible, that it will always have sufficient liquidity to meet liabilities when due. As of December 31, 2015, in addition to cash on hand of $124,353 the Company had $580,901 available to be drawn on its senior debt facilities. Each of the Company’s revolving credit facilities contain covenants which may limit amounts available to be drawn.

The Company’s liabilities mature as follows: 

	Due less than 1 year		Due 2 to 3 years		Due 4 to 5 years		Due after 5 years		Total
Long-term debt obligations	$	8,945	$	222,810	$	187,582	$	1,076,786	$	1,496,123
Advances in aid of construction	1,347		—		—		90,938		92,285
Interest on long-term debt	74,324		138,841		117,328		333,606		664,099
Purchase obligations	243,748		—		—		—		243,748
Environmental obligation	5,435		41,494		1,753		29,813		78,495
Derivative financial instruments:
Cross-currency swap	4,828		8,963		7,508		80,260		101,559
Interest rate swaps	—		9,659		—		—		9,659
Currency forward	1,918		—		—		—		1,918
Energy derivative and commodity contracts	1,885		237		—		—		2,122
Other obligations	12,808		—		—		40,694		53,502
Total obligations	$	355,238	$	422,004	$	314,171	$	1,652,097	$	2,743,510

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2015 and 2014

(in thousands of Canadian dollars, except as noted and per share amounts)

25. Subsequent event - Convertible Unsecured Subordinated Debentures

Subsequent to year-end, on March 1, 2016, the Company completed the sale of $1,000,000 aggregate principal amount of 5.0% convertible unsecured subordinated debentures. The Debentures were sold on an instalment basis at a price of $1,000 per Debenture, of which $333 was paid on closing of the Debenture Offering and the remaining $667 (the “Final Instalment”) is payable on a date (“Final Instalment Date”) to be fixed following satisfaction of conditions precedent to the closing of the acquisition of Empire. On March 9, 2016, the underwriters exercised their option to purchase $150,000 additional Debentures bringing the total amount of Debentures under the Debenture Offering to $1,150,000.

The Debentures will mature on March 31, 2026 and bear interest at an annual rate of 5% per $1,000 principal amount of Debentures until and including the Final Instalment Date, after which the interest rate will be 0%. Based on the first instalment of $333 per $1,000 principal amount of Debentures, the effective annual yield to and including the Final Instalment Date is 15%, and the effective annual yield thereafter is 0%.

If the Final Instalment Date occurs on a day that is prior to the first anniversary of the closing of the Debenture Offering, holders of Debentures who have paid the final instalment on or before the Final Instalment Date will be entitled to receive, on the business day following the Final Instalment Date, in addition to the payment of accrued and unpaid interest to and including the Final Instalment Date, an amount equal to the interest that would have accrued from the day following the Final Instalment Date to and including the first anniversary of the closing of the Debenture Offering had the Debentures remained outstanding and continued to accrue interest until and including such date (the “Make-Whole Payment”). No Make-Whole Payment will be payable if the Final Instalment Date occurs on or after the first anniversary of the closing of the Debenture Offering. Prior to the closing of the acquisition, the Company will at all times have cash on hand or maintain readily available capacity under the revolving credit facilities of not less than the aggregate amount of the first instalment paid on the closing of the Debenture Offering and the exercise of the over-allotment option.

At the option of the holders and provided that payment of the Final Instalment has been made, each Debenture will be convertible into common shares of the Company at any time after the Final Instalment Date, but prior to the earlier of maturity or redemption by the Company, at a conversion price of $10.60 per common share.

Prior to the Final Instalment Date, the Debentures may not be redeemed by the Company, except that Debentures will be redeemed by the Company at a price equal to their principal amount plus accrued and unpaid interest following the earlier of: (i) notification to holders that the conditions necessary to approve the acquisition of Empire will not be satisfied; (ii) termination of the acquisition agreement; and (iii) September 11, 2017 if notice of the Final Instalment Date has not been given to holders on or before September 8, 2017. Upon any such redemption, the Company will pay for each Debenture $333 plus accrued and unpaid interest to the holder of the instalment receipt. In addition, after the Final Instalment Date, any Debentures not converted may be redeemed by the Company at a price equal to their principal amount plus any unpaid interest, which accrued prior to and including the Final Instalment Date.

At maturity, the Company will have the right to pay the principal amount due in cash or in common shares. In the case of common shares, such shares will be valued at 95% of their weighted average trading price on the Toronto Stock Exchange for the 20 consecutive trading days ending five trading days preceding the maturity date.

26. Comparative figures

Certain of the comparative figures have been reclassified to conform to the financial statement presentation adopted in the current year.