Algonquin Power & Utilities (AQN) 40-F 2014 FY Annual report (Canada)

Consolidated Financial Statements of

Algonquin Power & Utilities Corp.

For the years ended December 31, 2014 and 2013

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, 2014, 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, 2014.

March 16, 2015

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

INDEPENDENT AUDITORS' REPORT OF REGISTERED PUBLIC ACCOUNTING FIRM

To the 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, 2014 and 2013 and the consolidated statements of operations, comprehensive income, equity, and cash flows for the years then ended, 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 United States 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, 2014 and 2013, and the consolidated results of its operations and its cash flows for the years then ended, in conformity with United States 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, 2014, 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 16, 2015 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 16, 2015

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

To the Shareholders of Algonquin Power & Utilities Corp.

We have audited Algonquin Power & Utilities Corp.’s internal control over financial reporting as of December 31, 2014, 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 United States 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, 2014, 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, 2014 and 2013, and the related consolidated statements of operations, comprehensive income, equity, and cash flows for the years then ended of Algonquin Power & Utilities Corp. and our report dated March 16, 2015 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP        

Chartered Professional Accountants,

Licensed Public Accountants

Toronto, Canada

March 16, 2015

Algonquin Power & Utilities Corp.

Consolidated Balance Sheets

(thousands of Canadian dollars)
	December 31, 2014		December 31, 2013
ASSETS
Current assets:
Cash and cash equivalents	$	9,273	$	13,839
Accounts receivable, net (note 4)	188,573		160,636
Natural gas in storage (note 1(g))	31,550		25,609
Supplies and consumables inventory	11,825		7,924
Regulatory assets (note 7)	61,645		26,125
Prepaid expenses	10,431		11,341
Notes receivable (note 8)	2,966		598
Deferred income taxes (note 20)	7,210		19,652
Income taxes receivable (note 20)	568		379
Derivative instruments (note 25)	10,688		9,176
Assets held for sale (note 17)	—		23,927
	334,729		299,206
Property, plant and equipment, net (note 5)	3,278,422		2,708,704
Intangible assets, net (note 6)	54,011		54,416
Goodwill (note 6)	92,328		84,647
Regulatory assets (note 7)	187,699		164,223
Derivative instruments (note 25)	31,782		27,123
Long-term investments (note 8)	43,279		32,746
Deferred income taxes (note 20)	57,065		86,632
Other assets (note 12)	35,100		18,784
	$	4,114,415	$	3,476,481

Algonquin Power & Utilities Corp.

Consolidated Balance Sheets

(thousands of Canadian dollars)
	December 31, 2014			December 31, 2013
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	68,540		$	14,489
Accrued liabilities	199,374			146,338
Dividends payable (note 16)	25,395			17,535
Regulatory liabilities (note 7)	20,590			21,632
Long-term liabilities (note 9)	9,130			8,339
Pension and other post-employment benefits (note 10)	333			305
Other long-term liabilities (note 13)	9,873			7,451
Advances in aid of construction (note 1(o))	1,149			1,239
Derivative instruments (note 25)	5,183			2,492
Environmental obligations (note 23(a)(ii))	19,643			10,111
Preferred shares, Series C (note 11)	1,085			1,038
Liabilities held for sale (note 17)	—			1,471
Income taxes liability (note 20)	3,633			5,159
Deferred credits (note 13)	18,638			7,778
Deferred income taxes (note 20)	3,702			2,308
	386,268			247,685
Long-term liabilities (note 9)	1,270,893			1,247,249
Advances in aid of construction (note 1(o))	79,955			77,697
Regulatory liabilities (note 7)	102,196			101,657
Deferred income taxes (note 20)	130,758			137,153
Derivative instruments (note 25)	40,088			13,729
Deferred credits (note 13)	13,624			17,115
Pension and other post-employment benefits (note 10)	138,602			70,532
Environmental obligation (note 23(a)(ii))	52,662			59,444
Other long-term liabilities (note 13)	33,227			20,492
Preferred shares, Series C (note 11)	17,608			17,767
	1,879,613			1,762,835
Redeemable non-controlling interest (note 3(c))	12,146			—
Equity:
Preferred shares (note 14(b))	213,805			116,546
Common shares (note 14(a))	1,633,262			1,351,264
Subscription receipts (note 14(a)(iii))	110,503			—
Additional paid-in capital	33,068			7,313
Deficit	(505,305		)	(488,406		)
Accumulated other comprehensive income (loss) (note 15)	34,213			(31,410		)
Total Equity attributable to shareholders of Algonquin Power & Utilities Corp.	1,519,546			955,307
Non-controlling interests	316,842			510,654
Total Equity	1,836,388			1,465,961
Commitments and contingencies (note 23)
Subsequent events (notes 3(a), 14(c)(iv) and 20)
	$	4,114,415		$	3,476,481

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
	2014			2013
Revenue
Regulated electricity distribution	$	206,667		$	166,156
Regulated gas distribution	446,025			260,424
Regulated water reclamation and distribution	66,419			57,350
Non-regulated energy sales	202,300			180,191
Other revenue	22,149			11,170
	943,560			675,291
Expenses
Operating	235,984			180,346
Regulated electricity purchased	120,506			97,376
Regulated gas purchased	261,116			148,784
Non-regulated energy purchased	39,264			25,835
Administrative expenses	34,692			23,518
Depreciation of property, plant and equipment	108,974			91,978
Amortization of intangible assets	4,626			4,200
Other amortization	447			(159		)
Gain on foreign exchange	(1,112		)	(567		)
	804,497			571,311
Operating income from continuing operations	139,063			103,980
Interest expense	62,418			53,426
Interest, dividend income and other income	(7,758		)	(7,785		)
Loss (gain) on sale of assets	(436		)	750
Acquisition-related costs	2,552			2,140
Write-down of long-lived assets	8,463			—
Loss (gain) on derivative financial instruments (note 25(b)(iv))	1,375			(5,200		)
	66,614			43,331
Earnings from continuing operations before income taxes	72,449			60,649
Income tax expense (note 20)
Current	3,674			2,526
Deferred	13,133			6,629
	16,807			9,155
Earnings from continuing operations	55,642			51,494
Loss from discontinued operations, net of tax (note 17)	(2,127		)	(42,011		)
Net earnings	53,515			9,483
Net loss attributable to non-controlling interests (note 19)	(22,186		)	(10,813		)
Net earnings attributable to shareholders of Algonquin Power & Utilities Corp.	$	75,701		$	20,296
Basic net earnings per share from continuing operations (note 21)	$	0.32		$	0.28
Basic net loss per share from discontinued operations (note 21)	(0.01		)	(0.21		)
Basic net earnings per share (note 21)	0.31			0.07
Diluted net earnings per share from continuing operations (note 21)	0.32			0.28
Diluted net loss per share from discontinued operations (note 21)	(0.01		)	(0.20		)
Diluted net earnings per share (note 21)	$	0.31		$	0.07

See accompanying notes to consolidated financial statements

Algonquin Power & Utilities Corp.

Consolidated Statements of Comprehensive Income

(thousands of Canadian dollars)	Year ended December 31
	2014			2013
Net earnings	$	53,515		$	9,483
Other comprehensive income:
Foreign currency translation adjustment, net of tax recovery of $1,049 and tax expense of $149, respectively (notes 1(v), 25(b)(iii) and 25(c))	100,548			81,597
Change in fair value of cash flow hedge, net of tax expense of $7,638 and $5,103, respectively (note 25(b)(ii))	6,434			17,308
Change in unrealized appreciation in value of available-for-sale investments	1			—
Change in pension and other post-employment benefits, net of tax recovery of $22,446 and tax expense of $10,896, respectively (note 10)	(35,669		)	16,727
Other comprehensive income, net of tax	71,314			115,632
Comprehensive income	124,829			125,115
Comprehensive income attributable to the non-controlling interests	7,077			31,362
Comprehensive income attributable to shareholders of Algonquin Power & Utilities Corp.	$	117,752		$	93,753

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, 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)(iii))	—		—		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	—		—		—		3,203		—			—			—			3,203
Preferred shares Series D, net of costs (note 14(b))	—		97,259		—		—		—			—			—			97,259
Acquisition of non-controlling interest (note 3(g))	—		—		—		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

Algonquin Power & Utilities Corp.

Consolidated Statement of Equity

(thousands of Canadian dollars) For the year ended December 31, 2013
	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, 2012	$	1,245,326	$	116,546	$	61,160		$	5,224	$	(406,143	)	$	(104,867	)	$	484,883		$	1,402,129
Net earnings (loss)	—		—		—			—		20,296			—			(10,813		)	9,483
Other comprehensive income	—		—		—			—		—			73,457			42,175			115,632
Dividends declared and distributions to non-controlling interests	—		—		—			—		(59,773		)	—			(5,591		)	(65,364		)
Dividends and issuance of shares under dividend reinvestment plan	13,970		—		—			—		(13,970		)	—			—			—
Exercise and conversion of subscription receipts	90,464		—		(90,464		)	—		—			—			—			—
Issuance of subscription receipts (note 14(a)(iii))	—		—		29,304			—		—			—			—			29,304
Conversion and redemption of convertible debentures	960		—		—			—		—			—			—			960
Issuance of common shares under employee share purchase plan	544		—		—			—		(17		)	—			—			527
Share-based compensation expense	—		—		—			2,089		—			—			—			2,089
Preferred shares, Series C (note 11)	—		—		—			—		(18,497		)	—			—			(18,497		)
Acquisition of non-controlling interest (note 18)	—		—		—			—		(10,302		)	—			—			(10,302		)
Balance, December 31, 2013	$	1,351,264	$	116,546	$	—		$	7,313	$	(488,406	)	$	(31,410	)	$	510,654		$	1,465,961

See accompanying notes to consolidated financial statements

Algonquin Power & Utilities Corp.

Consolidated Statements of Cash Flows

(thousands of Canadian dollars)	Year ended December 31
	2014			2013
Cash provided by (used in):
Operating Activities
Net earnings from continuing operations	$	55,642		$	51,494
Adjustments and items not affecting cash:
Depreciation of property, plant and equipment	108,974			91,978
Amortization of intangible assets	4,626			4,200
Other amortization	1,799			2,891
Deferred taxes	13,133			6,629
Unrealized loss (gain) on derivative financial instruments	3,046			(6,758		)
Share-based compensation	3,203			2,000
Cost of equity funds used for construction purposes	(1,910		)	(1,786		)
Pension and post-employment expense	(2,050		)	(302		)
Write-down of long-lived assets	8,463			—
Loss on sale of long-lived assets	—			750
Changes in non-cash operating items (note 24)	(1,790		)	(47,819		)
Changes in non-cash operating items from discontinued operations (note 24)	1,262			36
Cash used in discontinued operations (note 17)	(1,682		)	(4,388		)
	192,716			98,925
Financing Activities
Cash dividends on common shares	(57,848		)	(52,335		)
Cash dividends on preferred shares	(9,503		)	(5,400		)
Cash contributions from non-controlling interests	11,845			—
Production based cash contributions from non-controlling interest	8,976			1,672
Cash distributions to non-controlling interests	(4,738		)	(7,263		)
Issuance of common shares, net of costs	261,452			29,983
Proceeds from subscription receipts	110,503			—
Issuance of preferred shares, net of costs	96,271			—
Deferred financing costs	(3,043		)	(2,240		)
Increase in deferred insurance proceeds & revenue	13,132			—
Acquisition of non-controlling interest	(127,121		)	—
Increase in long-term liabilities	236,528			950,346
Decrease in long-term liabilities	(286,552		)	(685,472		)
Increase (decrease) in advances in aid of construction	(48		)	2,299
Increase (decrease) in other long-term liabilities	5,486			(1,574		)
	255,340			230,016
Investing Activities
(Increase) decrease in restricted cash	(11,034		)	1,430
Increase in other assets	(2,751		)	(3,004		)
Distributions received in excess of equity income	264			727
Proceeds from sale of discontinued operations	20,826			24,968
Receipt of principal on notes receivable	280			109
Additions to property, plant and equipment	(432,373		)	(158,377		)
Acquisitions of long-term investments	(25,432		)	—
Acquisitions of operating entities	(8,757		)	(239,014		)
Proceeds from sale of investment	5,709			3,408
	(453,268		)	(369,753		)
Effect of exchange rate differences on cash	646			1,529
Decrease in cash and cash equivalents	(4,566		)	(39,283		)
Cash and cash equivalents, beginning of year	13,839			53,122
Cash and cash equivalents, end of year	$	9,273		$	13,839
Supplemental disclosure of cash flow information:	2014			2013
Cash paid during the year for interest expense	$	60,682		$	44,185
Cash paid during the year for income taxes	$	2,571		$	1,107
Non-cash transactions: Property, plant and equipment acquisitions in accruals	$	25,568		$	10,829

See accompanying notes to consolidated financial statements

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2014 and 2013

(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 non-regulated generation business group operates under the name Algonquin Power Co. (“Generation Group”) and owns or has interests in a portfolio of 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 accompanying notes have been prepared in accordance with generally accepted accounting principles in the United States (“U.S. GAAP”) and follow disclosures required under Regulation S-X provided by the Securities and Exchange Commission (“SEC”).  

(b) Basis of consolidation

The accompanying consolidated financial statements of APUC include the accounts of APUC and its wholly owned subsidiaries and variable interest entities (“VIEs”) where the Company is the primary beneficiary (note 1(m)). Intercompany transactions and balances have been eliminated. 

(c) 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 commissions 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 revenues 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 (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 and gas utilities’ and the 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, respectively. 

(d) Cash and cash equivalents

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

(e) 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.

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2014 and 2013

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

1. Significant accounting policies (continued)

(f) 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.

(g) 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. Existing rate orders allow the Company to pass through the cost of gas purchased directly to the rate payers 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 (note 7(d)).

(h) 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.

(i) Property, plant and equipment

Property, plant and equipment, consisting of renewable and thermal generation assets, electrical, gas, water and wastewater distribution assets, equipment and land, are recorded at cost. 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 equity funds used during construction (“AFUDC”) for regulated property. 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 and other income on the consolidated statements of operations. 

	2014		2013
Interest capitalized on non-regulated property	$	3,584	$	669
AFUDC capitalized on regulated property:
Allowance for borrowed funds	1,577		1,055
Allowance for equity funds	1,910		1,786
Total	$	7,071	$	3,510

Improvements that increase or prolong the service life or capacity of an asset are capitalized. Maintenance and repair costs are expensed as incurred. 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.

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2014 and 2013

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

1. Significant accounting policies (continued)

(i) Property, plant and equipment (continued)

Investment tax credits and government grants 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 1(o)) 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.

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. The ranges of estimated useful lives and the weighted average useful lives are summarized below:

	Range of useful lives		Weighted average useful lives
	2014	2013	2014	2013
Generation Group
Renewable	3 – 60	3 – 60	36	35
Thermal	3 – 40	3 – 40	25	24
Distribution Group
Gas	5 – 100	5 – 80	41	38
Electrical	5 – 75	8 – 75	41	41
Water & wastewater	5 – 75	5 – 50	39	39
Equipment	5 – 50	5 – 50	14	24

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. 

(j) Intangible assets

The fair value of power sales contracts acquired in business combinations is amortized on a straight-line basis over the remaining term of the contract. The periods range from 6 to 25 years from the date of acquisition.

Customer relationships acquired in business combinations are amortized on a straight-line basis over their estimated life of 40 years.

(k) Goodwill

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, and when indicators of impairment are present, 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, 2014 and 2013

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

1. Significant accounting policies (continued)

(l) 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 the 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.

(m) Variable interest entities

The Company performs analyses 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. The primary beneficiary of a VIE has both the power to direct the activities of the entity that most significantly impact its economic performance and the right to receive benefits or the obligation to absorb losses of the entity that could potentially be significant to the entity. In circumstances where APUC is not deemed the primary beneficiary, the VIE is not consolidated (note 8(a)).

The Long Sault Hydroelectric Facility ("Long Sault") is a hydroelectric generating facility in which APUC acquired an interest by way of subscribing to two notes from the original developers. The notes receivable effectively provide APUC the right to 70% after tax cash flows of the facility from 2014 to 2027 and 62.5% thereafter. The Company also has the right to acquire 58% of the equity in the facility at the end of the term of the notes in 2038.  Effective December 31, 2013, APUC acquired an equity interest in Long Sault (note 18). APUC has determined that the facility is a VIE. Since the Company is the primary beneficiary, the Long Sault entity is subject to consolidation by the Company. Total net book value of generating assets and long-term debt of Long Sault amounts to $42,689 (2013 - $44,319) and $36,049 (2013 - $37,143), respectively. The Long Sault debt only has recourse over the Long Sault generating assets. The financial performance of Long Sault reflected on the consolidated statements of operations includes non-regulated energy sales of $10,778 (2013 - $10,155), operating expenses and amortization of $3,201 (2013 - $2,391) and interest expense of $3,781 (2013 - $3,632).

The Saint-Damase Wind Powered Generating Facility ("Saint-Damase") is a 24 megawatt ("MW") wind powered generating facility located near St. Damase, Quebec which achieved commercial operation on December 2, 2014. The Company owns a 50% interest in the corporation with the remaining 50% interest held by the Municipality of Saint-Damase. The Company also provided subordinated construction loans to the project. APUC has determined that the corporation holding the facility is a VIE. Since the Company is the primary beneficiary, Saint- Damase is subject to consolidation by the Company. Total net book value of generating assets and third-party long-term debt of Saint-Damase amounts to $69,655 and $23,400, respectively. The financial performance of Saint-Damase reflected on the consolidated statements of operations for its first month of operations in 2014 includes non-regulated energy sales of $440, operating expenses and amortization of $217 and interest expense of $39.

(n) Long-term investments and notes receivable

Investments in which APUC has significant influence but are not controlled 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 and other income in the consolidated statements of operations.

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2014 and 2013

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

1. Significant accounting policies (continued)

(n) Long-term investments and notes receivable (continued)

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.

(o) 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. These amounts are recorded as Advances in aid of construction on the consolidated balance sheet.

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 2014, $4,608 (2013 - $627) was transferred from advances in aid of construction to contributions in aid of construction.

(p) Deferred water rights and customer deposits

Deferred water rights are related to a hydroelectric generating facility which has a fifty-year water lease with the first ten years of the water lease requiring no payment, which is a form of lease inducement. An annual average rate for water rights was estimated for the entire life of the lease and that average rate is being expensed over the lease term. The result of this policy is that the deferred water rights inducement amount recorded in the first ten years is being drawn down in the last forty years.

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. The deposits bear monthly interest and are applied to the customer account after 12 months if the customer is found to be creditworthy. 

(q) 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. 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, 2014 and 2013

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

1. Significant accounting policies (continued)

(r) 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, construction, development 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 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 accumulated obligation.

(s) Share-based compensation

The Company has several share-based compensation plans: a share option plan; an employee common share purchase plan (“ESPP”); a deferred share unit (“DSU”) plan; and a performance share unit (“PSU”) plan. The Company recognizes all employee share-based compensation as a cost in the consolidated financial statements. 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.

(t) Non-controlling interests

Non-controlling interest represents the portion of equity ownership in subsidiaries that is not attributable to the equity holders of the parent company. Non-controlling interests are initially recorded at fair value and subsequently the amount is 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.

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 19).

If a transaction results in the acquisition of all, or part, of a non-controlling interest in a 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.

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. At each balance sheet date, 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 accumulated 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, 2014 and 2013

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

1. Significant accounting policies (continued)

(u) 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.

Revenues related to utility electricity and natural gas sales and distribution are recorded based on metered consumptions by customers, which occur on a systematic basis throughout a month, rather than 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 revenues are calculated. 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 and New England Gas Systems is subject to a revenue decoupling mechanism approved by their respective regulator which require to charge approved annual delivery revenues 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(j)).

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 revenues are calculated. These estimates of unbilled revenues 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 sale taxes. 

During the year, the Company settled insurance claims for business interruption at some of its renewable generation facilities under repairs and as a result recognized revenue of $1,227 (2013 - $6,455).

(v) 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 revenues 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.

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2014 and 2013

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

1. Significant accounting policies (continued)

(w) 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. Investment tax credits are recorded as an offset to the related long-lived asset and are amortized over the estimated life of the asset as credits to income tax expense.

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.

(x) Financial instruments and derivatives

Accounts receivable and notes receivable are measured at amortized cost and there is no liquid market for these investments. Long-term liabilities, Series C preferred shares and other long-term liabilities 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 respective asset’s carrying value at inception. Transaction costs that are directly attributable to the issuance of financial liabilities, costs of arranging the Company’s revolving credit facilities and costs considered as commitment fees paid to financial institutions are recorded in deferred financing costs. 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 are amortized on a straight-line basis over the term of the respective revolving credit facility.

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 financial instruments used to manage its foreign currency risk exposure 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 as 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 recognized in AOCI is transferred to the consolidated statements of operations in the same period that the hedged item affects earnings. If the forecast transaction is no longer expected to occur, then the balance in AOCI is recognized immediately in earnings.

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2014 and 2013

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

1. Significant accounting policies (continued)

(x) Financial instruments and derivatives (continued)

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.

Calpeco Electric System and Granite State Electric System enter into power purchase agreements (“PPA”) for load serving 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.

(y) 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 measurement date.

(z) 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.

(aa) 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, 2014 and 2013

(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 2013-11, Income Taxes (Topic 740): Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists. This newly issued accounting standard requires an entity to present an unrecognized tax benefit, or a portion of an unrecognized tax benefit as a reduction to a deferred income tax asset for a net operating loss carryforward, a similar tax loss, or a tax credit carryforward, except in some specific situations. The adoption of this standard did not have an impact on the Company’s financial position or results of operations.

The FASB issued ASU 2013-10, Derivatives and Hedging (Topic 815): Inclusion of the Fed Funds Effective Swap Rate (or Overnight Index Swap Rate) as a Benchmark Interest Rate for Hedge Accounting Purposes. This newly issued accounting standard permits the Fed Funds Effective Swap Rate (OIS) to be used as a U.S. benchmark interest rate for hedge accounting purposes under Topic 815, in addition to interest rates on direct Treasury obligations of the U.S. government and the London Interbank Offered Rate. The amendments also remove the restriction on using different benchmark rates for similar hedges. The adoption of this standard did not have an impact on the Company’s financial position or results of operations.

The FASB issued ASU 2013-04, Liabilities (Topic 405): Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation Is Fixed at the Reporting Date. This newly issued accounting standard provides guidance for the recognition, measurement, and disclosure of obligations resulting from joint and several liability arrangements for which the total amount of the obligation within the scope of this guidance is fixed at the reporting date, except for obligations addressed within existing guidance in U.S. GAAP. Examples of obligations within the scope of this update include debt arrangements, other contractual obligations, and settled litigation and judicial rulings. The adoption of this standard did not have an impact on the Company’s financial position or results of operations. 

(b) Recent accounting guidance not yet adopted

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, 2014 and 2013

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

2.     Recently issued accounting pronouncements (continued)

(b) Recent accounting guidance not yet adopted (continued)

The FASB issued ASU No. 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 No. 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 No. 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 No. 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 No. 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. This ASU is required to be applied for fiscal years and interim periods beginning after December 15, 2016 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.

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. This ASU is required to be applied prospectively for fiscal years and interim periods beginning after December 15, 2014. The adoption of this standard is not expected to have an impact on the Company's financial position or results of operations.

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2014 and 2013

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

3. Business acquisitions and development projects

(a) Acquisition of New Hampshire Gas

Subsequent to year-end , 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 approximately U.S. $3,047, subject to certain closing adjustments.

(b) Agreement to acquire Park Water System

On September 19, 2014, the Company entered into an agreement to acquire the regulated water distribution utility Park Water Company (“Park Water System”). 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. Total consideration for the utility purchase is expected to be approximately U.S. $327,000, which includes the assumption of approximately U.S. $77,000 of existing long-term utility debt and is subject to certain working capital and other closing adjustments. Closing of the transaction is subject to certain conditions including state and federal regulatory approval, and is expected to occur in the latter half of 2015.

(c) Development of Bakersfield Solar Project

During the year, the Company constructed a 20 MWac solar powered generating facility located in Kern County, California. As of December 31, 2014, the Company has incurred U.S $56,814 in the development and construction of the solar energy project which is recorded as property, plant and equipment. The facility was placed in service on December 31, 2014. Sales of power to the utility under the power purchase agreement is planned for early 2015.

On August 13, 2014, the Generation Group entered into a definitive partnership agreement with a third-party (the "Tax Investor"). It is anticipated that approximately U.S. $22,800 will be funded by the Tax Investor. With its partnership interest, the Tax Investor will receive the majority of the tax attributes associated with the project. The Tax Equity investment as of December 31, 2014 is U.S. $10,470.

Under certain conditions, the Tax Investor has the right to withdraw from the Bakersfield Solar Project and require the Company to redeem its interests for cash over a contractual payment period. As a result, the Company accounts for this interest as temporary equity and records this interest outside of permanent equity on the consolidated balance sheets as "Redeemable non-controlling interest". The Company records temporary equity at issuance based on cash received less any transaction costs. As of December 31, 2014, transaction costs of $956 have been recorded as a reduction to Redeemable non-controlling interest.

At each balance sheet date, the Company will reevaluate the classification of its redeemable instrument, as well as the probability of redemption. If the redemption amount is probable or currently redeemable, the Company will record the instruments at its redemption value. Increases or decreases in the carrying amount of a redeemable instrument will be recorded within accumulated deficit. Redemption is not considered probable as of December 31, 2014.

(d) Commercial operation of Saint-Damase Wind Facility

Saint-Damase is a 24 MW wind powered generating facility located near St. Damase, Quebec which achieved commercial operation on December 2, 2014. Total net book value of generating assets of Saint-Damase amounts to $69,655. Property, plant and equipment are amortized over the estimated useful life of the assets using the straight-line method. The weighted average useful life of the Saint-Damase Wind Generating Facility is 35 years.

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2014 and 2013

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

3. Business acquisitions and development projects (continued)

(e) Commercial operation of Cornwall Solar Facility

On March 27, 2014, the Cornwall Solar Facility, a 10 MWac solar powered generating facility located near Cornwall, Ontario, commenced commercial operations. The Company invested $41,551 in the development and construction of the solar energy project which is recorded as property, plant and equipment, as well as additional amounts related to development rights and other intangible assets, for a total investment of $47,561. Property, plant and equipment are amortized over the estimated useful life of the assets using the straight-line method. The weighted average useful life of the Cornwall Solar Powered Facility is 33 years.

(f) 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.

(g) 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") from Gamesa Corporación Tecnológica, S.A. 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

(h) 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 Q2 2014.

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2014 and 2013

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

3. Business acquisitions and development projects (continued)

(h) Acquisition of New England Gas System (continued)

In 2014, the Company received additional information which was used to refine the estimates for fair value of assets acquired and liabilities assumed. The carrying value of those assets and liabilities were retrospectively adjusted to the amounts detailed in the table below. The key adjustments were an increase to the regulatory asset for pension of U.S. $4,642, a decrease of property, plant and equipment of U.S. $1,190, an increase of the environmental obligation of U.S. $4,408 and an increase of the pension obligation of U.S. $772.

Working capital	$	7,543
Restricted cash	595
Property, plant and equipment	83,365
Regulatory assets	52,601
Other assets	1,221
Long-term debt	(25,349		)
Regulatory liabilities	(9,874		)
Pension and OPEB	(26,184		)
Environmental obligation	(14,933		)
Deferred income tax liability, net	(1,158		)
Other liabilities	(817		)
Total net assets acquired	$	67,010

The determination of the fair value is based upon management’s estimates and assumptions with respect to the fair values of the assets acquired and liabilities assumed.

Property, plant and equipment are amortized in accordance with regulatory requirements over the estimated useful life of the assets using the straight-line method. The weighted average useful life of the New England Gas System assets is 31 years.

All costs related to the acquisition have been expensed through the consolidated statements of operations.

The New England Gas System contributed revenue of $91,782 (2013 - $3,582) and net earnings of $10,819 (2013 - $1,153) to the Company’s consolidated financial results for 2014.

(i) 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 2015. 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, a gain of U.S. $1,133 was recognized in 2014.

4. Accounts receivable

Accounts receivable as of December 31, 2014 include unbilled revenue of $52,880 (December 31, 2013 - $45,274) from the Company's regulated utilities. Accounts receivable as of December 31, 2014 are presented net of allowance for doubtful accounts of $7,229 (December 31, 2013 - $8,461).

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2014 and 2013

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

5. Property, plant and equipment

Property, plant and equipment consist of the following: 

2014
	Cost		Accumulated depreciation		Net book value
Generation Group
Renewable	$	1,697,020	$	217,615	$	1,479,405
Thermal	130,227		53,131		77,096
Distribution Group
Water & wastewater	358,520		78,290		280,230
Electricity	347,633		23,659		323,974
Gas	849,136		45,777		803,359
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

2013
	Cost		Accumulated depreciation		Net book value
Generation Group
Renewable	$	1,438,229	$	166,175	$	1,272,054
Thermal	116,975		43,596		73,379
Distribution Group
Water & wastewater	303,410		63,807		239,603
Electricity	277,679		16,782		260,897
Gas	682,445		15,769		666,676
Land	8,266		—		8,266
Equipment and other	78,881		29,100		49,781
Construction in progress
Generation	54,432		—		54,432
Distribution	83,616		—		83,616
	$	3,043,933	$	335,229	$	2,708,704

Renewable generation assets include cost of $155,629 (2013 - $86,774) and accumulated depreciation of $34,013 (2013 - $31,739) related to facilities under capital lease or owned by consolidated VIEs. Depreciation expense of facilities under capital lease was $2,274 (2013 - $2,155).

Investments tax credits, government grants and contributions received in aid of construction of $362 (2013 - $3,098) have been credited to the cost of the distribution assets. Water and wastewater distribution assets include expansion costs of $1,000 on which the Company does not currently earn a return. 

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2014 and 2013

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

6. Intangible assets and goodwill

Intangible assets consist of the following:

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

2013
	Cost		Accumulated amortization		Net book value
Power sales contracts	$	61,430	$	28,987	$	32,443
Customer relationships	28,512		6,539		21,973
	$	89,942	$	35,526	$	54,416

Estimated amortization expense for intangible assets for the next two years is $4,750 each year, $3,000 in year three, $2,640 in year four and $2,580 in year five.

Changes in goodwill are as follows:

	Distribution Group
Balance, January 1, 2013	$	61,459
Business acquisitions	17,260
Adjustments	748
Foreign exchange	5,180
Balance, December 31, 2013	$	84,647
Foreign exchange	7,681
Balance, December 31, 2014	$	92,328

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 revenues 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.

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2014 and 2013

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

7. Regulatory matters (continued)

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 service 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 service rendered on and after February 1, 2014.

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.

Regulatory assets and liabilities consist of the following: 

	2014			2013
Regulatory assets
Environmental costs (a)	$	102,735		$	85,029
Pension and post-employment benefits (b)	65,745			64,997
Storm costs (c)	3,080			5,437
Commodity costs adjustment (d)	41,502			15,904
Rate case costs (e)	4,161			3,119
Vegetation management	3,260			2,297
Debt premium (f)	4,658			4,504
Rate adjustment mechanism (j)	6,207			28
Asset retirement obligation (g)	1,682			1,468
Tax related	4,350			2,995
Other	11,964			4,570
Total regulatory assets	$	249,344		$	190,348
Less current regulatory assets	(61,645		)	(26,125		)
Non-current regulatory assets	$	187,699		$	164,223
Regulatory liabilities
Cost of removal (h)	$	78,013		$	68,698
Rate-base offset (i)	23,427			25,082
Commodity costs adjustment (d)	10,389			17,394
Pension and post-employment benefits (b)	592			6,770
Rate adjustment mechanism (j)	448			1,681
Storm costs (c)	1,030			—
Depreciation adjustment mechanism	3,518			—
Tax related	145			133
Other	5,224			3,531
Total regulatory liabilities	$	122,786		$	123,289
Less current regulatory liabilities	(20,590		)	(21,632		)
Non-current regulatory liabilities	$	102,196		$	101,657

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2014 and 2013

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

7. Regulatory matters (continued)

(a) Environmental remediation costs recovery: Actual expenditures incurred for the clean-up of certain former gas manufacturing facilities (note 23 (a)(ii)) are recovered through rates over a period of 7 years and in a jurisdiction are subject to an annual cap.

(b) Pension and post-employment benefits: As part of 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 $28,284 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 in 2015. 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-Nonretirement Postemployment Benefits and ASC 715 Compensation-Retirement Benefits before the transfer to regulatory asset occurred.

(c) Storm costs: Incurred repair costs resulting from certain storms over or under amounts collected from customers, which are expected to be recovered or refunded through rates.

(d) 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 25(b)(i)) are recoverable through the commodity costs adjustment.

(e) 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.

(f) Debt premium: The value of debt assumed in the acquisition of the New England Gas System has been recorded at fair value in accordance with ASC 805 Business Combinations. The Massachusetts regulator allows for recovery of interest at the coupon rate of the debt and a regulatory asset has been recorded for the difference between the fair value and face value of the debt. The debt premium is recovered over the remaining term of the debt (note 9).

(g) Asset retirement obligation: Asset retirement obligations incurred by the utilities are expected to be recovered through rates.

(h) 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.

(i) 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.

(j) Rate adjustment mechanism: Revenue for Calpeco Electric System and Peach State Gas System is subject to a revenue decoupling mechanism approved by their respective regulator which require charging approved annual delivery revenues 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 twenty-four months is accrued upon approval of the Final Order.

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 costs adjustment, rate case costs, vegetation management and storm costs in some jurisdictions.

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2014 and 2013

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

8. Long-term investments

Long-term investments consist of the following:

	2014			2013
Equity-method investees
50% interest in Odell Wind Project (a)	$	2,267		$	—
2.5% interest in natural gas pipeline development (b)	1,063			—
32.4% of Class B non-voting shares of Kirkland Lake Power Corp. (c)	1,512			4,851
25% of Class B non-voting shares of Cochrane Power Corporation (c)	—			3,772
50% interest in the Valley Power Partnership	1,253			1,718
Other	640			325
Total	$	6,735		$	10,666
Notes receivable
Development loans (a)	$	17,582		$	—
Red Lily Senior loan, interest at 6.31% (d)	11,588			11,588
Red Lily Subordinated loan, interest at 12.5% (d)	6,565			6,565
Chapais Énergie, Société en Commandite interest at 10.789%	649			1,928
Silverleaf resorts loan, interest at 15.48% maturing July 2020	2,344			2,149
Other	782			448
	39,510			22,678
Less current portion	(2,966		)	(598		)
Total	$	36,544		$	22,080
Total long-term investments	$	43,279		$	32,746

(a)Odell Wind Project

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.

On the acquisition of the Odell Wind Project by Odell SponsorCo, the two members each contributed U.S. $1,000 to the capital of Odell SponsorCo. Upon execution of third-party construction loan and tax equity documents expected in the second quarter of 2015, each party will contribute another U.S. $23,800 to the capital of Odell SponsorCo. The Company holds an option to acquire the other 50% interest for total contributions, subject to certain adjustments, on commencement of operations, which is expected in late 2015 or early 2016.

As of December 31, 2014, 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 $311,966 as of December 31, 2014.

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2014 and 2013

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

8. Long-term investments (continued)

(a)Odell Wind Project (continued)

The Company entered into a committed loan and credit support facility with Odell SponsorCo. During construction, the Company is obligated to provide Odell SponsorCo 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 Odell Wind Project. The loan bears interest at an annual rate of 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 Odell SponsorCo, to the extent not otherwise repaid earlier, is repayable in cash on the fifth anniversary of the availability termination date which is thirty days following the commercial operation date.

As of December 31, 2014, the Company had loaned U.S. $13,159 to Odell SponsorCo for development costs of the Odell Wind Project. No interest revenue was accrued on the loan due to insufficient collateral in Odell SponsorCo. The following credit support was also 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; guarantee of the obligations of the Odell Wind Project under the wind turbine supply agreement between Odell SponsorCo and Vestas-American Wind Technology, Inc.; a U.S.$23,800 letter of credit on behalf of Odell SponsorCo, to Enel Kansas, LLC under the purchase and sale agreement. The guarantee obligations are recognized under other long-term liabilities and were valued at U.S. $720 using a probability weighted discounted cash flow (level 3).

(b) Natural Gas Pipeline Development

On November 24, 2014, APUC announced that it plans to participate in the development of Kinder Morgan Inc's proposed Northeast Energy Direct natural gas pipeline project. The Company and Kinder Morgan Operating L.P. "A" formed a new entity ("Northeast Expansion LLC") to undertake the development, construction and ownership of a 30-inch or 36-inch natural gas transmission pipeline to be constructed between Wright, NY and Dracut, MA.  The pipeline capacity will be contracted with local distribution utilities, and other customers in the northeast U.S. The project is expected to reach commercial operations by late 2018. Under the agreement, APUC initially subscribed for a 2.5% interest in Northeast Expansion LLC with an opportunity to increase its participation up to 10%.  The total capital investment assuming APUC exercises its right to subscribe for 10% of the pipeline is expected be up to U.S. $400,000, depending on the final pipeline configuration and design capacity by the end of 2018. As of December 31, 2014, APUC had invested U.S. $375 in Northeast Expansion LLC. 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.

(c)Kirkland Lake Power Corp. and Cochrane Power Corporation

In September 2014, the Company was informed that future cash flows from its investments in Kirkland Lake Power Corp. ("Kirkland") and Cochrane Power Corporation ("Cochrane") are likely to be significantly reduced in the future based on the current power purchase rates negotiations. As the loss in value of these investments is considered other than temporary, an allowance for impairment of $3,414 and $3,772 on Kirkland and Cochrane, respectively, was recorded in the consolidated statements of operations. The fair value of the investments (level 3) was estimated using cash flow information provided by the investees.

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2014 and 2013

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

8. Long-term investments (continued)

(d) Red Lily I

The Red Lily I Partnership (the “Partnership”) is owned by an independent investor. The Company 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 debt facility, and a subordinated debt facility 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. Another 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 earns interest at the rate of 6.31% and will mature in 2016. Tranche 1 is being repaid in equal blended monthly payments of principal and interest at a rate of 6.99% based upon a twenty-five year amortization. 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.

A second tranche of subordinated loan for an amount equal to the amounts outstanding on Tranche 2 of the senior debt but no greater than $17,000 will be advanced in 2016 by the Company. The proceeds from this additional subordinated debt are required to be used 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 been granted an option to subscribe for a 75% equity interest in the Partnership in exchange for the outstanding amount on its subordinated loan of up to $19,500, exercisable for a period of 90 days commencing in 2016. The fair value of the conversion option as of December 31, 2014 and 2013 was determined to be negligible. 

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

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2014 and 2013

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

9. Long-term liabilities

Long-term liabilities consist of the following:

	2014			2013
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, 2018.	$	23,400		$	124,570
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.	484,553			284,757
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, maturing June 30, 2026.  The facility has principal and interest payments, payable semi-annually in arrears.	88,168			129,759
Long Sault Hydro Facility: Senior Debt: Bonds bearing an interest rate of 10.21% maturing December 31,2027. The bonds have interest and principal payments, payable monthly in arrears.	36,048			37,143
Sanger Thermal Facility: Senior Debt: U.S. $19,200 California Pollution Control Finance Authority Variable Rate Demand Resource Recovery Revenue Bond Series 1990A, bearing an effective interest rate determined by the remarketing agent. The bond has interest only payments, payable monthly in arrears. The effective interest rate in 2014 was 2.01% (2013 – 1.72%). The bonds were fully repaid on December 31, 2014.	—			20,421
Chuteford Hydro Facility: Senior Debt: Bonds bearing an interest rate of 11.6%, maturing April 1, 2020. The bond has principal and interest payments, payable monthly in arrears.	3,028			3,417
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			85,620
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. The notes have interest only payments, payable semi-annually.	423,436			388,214

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2014 and 2013

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

	2014			2013
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.	81,207			74,452
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.	58,005			53,180
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.	27,288			25,244
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; and, U.S. $5,000, bearing an interest rate of 7.30%, maturing June 15, 2028. The notes have interest only payments, payable semi-annually.	17,402			15,954
LPSCo Water System: 1999 and 2001 IDA Bonds bearing interest rates of 5.95% and 6.75% and maturing October 1, 2023 and October 1, 2031, respectively. The bonds have principal and interest payments, payable monthly in arrears.	12,441			11,668
Bella Vista Water System: 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.	1,149			1,189
	$	1,280,023		$	1,255,588
Less: current portion	(9,130		)	(8,339		)
	$	1,270,893		$	1,247,249

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2014 and 2013

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

9. Long-term liabilities (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. Noncompliance with the covenants could restrict cash distributions/dividends to the Company from the specific facilities.

Generation Group

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 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 25(b)(iii)).

Effective January 1, 2013, concurrent with the acquisition of Shady Oaks Wind Facility (note 3(i)), the Company assumed existing long-term debt of approximately U.S. $150,000. Principal of U.S. $46,000 was repaid in 2014 leaving a balance of U.S. $76,000 outstanding as of December 31, 2014. The semi-annual principal repayment schedule for the following 11.5 years ranges from U.S. $3,000 to U.S. $6,000 with a final repayment in 2026. This debt may be repaid in whole or in part on an interest payment date, annually May 15 or November 15, without penalty.

Distribution Group

On December 20, 2013, in connection with the acquisition of the New England Gas System, the Company assumed first mortgage bonds of U.S. $6,000, bearing an interest rate of 7.24%, maturing December 15, 2027; U.S. $7,000, bearing an interest rate of 7.99%, maturing September 15, 2026; and, U.S. $6,500, bearing an interest rate of 9.44%, maturing February 15, 2020.

On September 30, 2013, the Company increased the maximum availability under its senior unsecured revolving credit facility from U.S. $100,000 to $200,000 to meet future working capital requirements and allow for greater financial flexibility. The revolving credit facility has a maturity date of September 30, 2018.

On July 31, 2013, the Company issued U.S. $125,000 of senior unsecured notes through a private placement in three tranches: U.S. $25,000, bearing an interest rate of 3.23%, maturing July 31, 2020; U.S. $75,000, bearing an interest rate of 3.86%, maturing July 31, 2023; and, U.S. $25,000, bearing an interest rate of 4.26%, maturing July 31, 2028.  The proceeds from the private placement financing were used to fund a portion of the acquisition of the Peach State Gas System.

On March 14, 2013, the Company issued U.S. $15,000 of senior unsecured notes through a private placement in connection with the acquisition of the Pine Bluff Water System. The notes bear interest at 4.14% and mature March 13, 2023.

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2014 and 2013

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

9. Long-term liabilities (continued)

APUC

On November 19, 2013, APUC increased the maximum availability under its senior unsecured revolving credit facility from U.S. $30,000 to $65,000. The revolving credit facility will be used for general corporate purposes and has a maturity date of November 19, 2016. As of December 31, 2014 and 2013, no amounts were outstanding under this revolving credit facility.

As of December 31, 2014, the Company had accrued $18,770 in interest expense (2013 - $14,057). Interest paid on the long-term liabilities in 2014 was $61,287 (2013 - $49,746).

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

	2015		2016		2017		2018		2019		Thereafter		Total
Generation Group	$	8,599	$	8,779	$	11,300	$	169,822	$	12,132	$	424,517	$	635,149
Distribution Group	531		6,393		64,435		30,349		6,492		536,626		644,826
Total	$	9,130	$	15,172	$	75,735	$	200,171	$	18,624	$	961,143	$	1,279,975

10. Pension and other post-employment benefits

The Company provides defined contribution pension plans to its employees. The Company's contributions for 2014 were $3,287 (2013 - $2,437).

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. Benefits are based on each employee’s years of service and compensation. The Company initiated 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, 2014 and 2013

(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
	2014			2013			2014			2013
Change in projected benefit obligation
Projected benefit obligation, beginning of year	$	178,113		$	104,291		$	45,399		$	31,674
Projected benefit obligation assumed from business combination	1,022			73,601			—			17,943
Modifications to pension plan	(560		)	81			—			—
Service cost	4,828			3,273			2,022			1,602
Interest cost	8,549			4,350			2,186			1,508
Actuarial loss (gain)	39,704			(11,395		)	14,893			(8,499		)
Benefits paid	(8,125		)	(3,597		)	(1,255		)	(1,158		)
Loss on foreign exchange	18,432			7,509			5,012			2,329
Projected benefit obligation, end of year	$	241,963		$	178,113		$	68,257		$	45,399
Change in plan asset
Fair value of plan assets, beginning of year	139,280			66,524			13,395			10,195
Plan assets acquired in business combination	—			57,285			—			658
Actual return on plan assets	6,568			10,733			1,176			1,730
Employer contributions	5,676			3,013			(222		)	1,208
Benefits paid	(7,414		)	(3,597		)	(1,255		)	(1,157		)
Gain on foreign exchange	12,880			5,322			1,201			761
Fair value of plan assets, end of year	$	156,990		$	139,280		$	14,295		$	13,395
Unfunded status	$	(84,973	)	$	(38,833	)	$	(53,962	)	$	(32,004	)
Amounts recognized in the consolidated balance sheets consists of:
Current liabilities	—			(305		)	(333		)	—
Non-current liabilities	(84,973		)	(38,528		)	(53,629		)	(32,004		)
Net amount recognized	$	(84,973	)	$	(38,833	)	$	(53,962	)	$	(32,004	)

The accumulated benefit obligation for the pension plans was $219,007 and $162,179 as of December 31, 2014 and 2013, respectively.

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2014 and 2013

(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 AOCI before tax were as follows: 

	AOCI
	Pension			OPEB
Balance, January 1, 2013	$	3,333		$	821
Current year net actuarial gain	(17,777		)	(9,878		)
Current year prior service loss	82			—
Amortization of net actuarial loss	(23		)	(26		)
Balance at December 31, 2013	$	(14,385	)	$	(9,083	)
Current year net actuarial loss	43,350			14,338
Current year prior service credit	(563		)	—
Amortization of net actuarial gain	349			641
Balance at December 31, 2014	$	28,751		$	5,896

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 $1,074 and $356, respectively. 

(b) Assumptions

Weighted average assumptions used to determine net benefit cost for 2014 and 2013 were as follows: 

	Pension benefits				OPEB
	2014		2013		2014		2013
Discount rate	4.55	%	3.68	%	4.60	%	3.69	%
Expected return on assets	7.00	%	5.51	%	5.53	%	5.18	%
Rate of compensation increase	2.97	%	3.13	%	N/A		N/A
Health care cost trend rate
Before Age 65					7.63	%	7.68	%
Age 65 and after					7.63	%	7.68	%
Assumed Ultimate Medical Inflation Rate					5.00	%	4.80	%
Year in which Ultimate Rate is reached					2019		2019

Weighted average assumptions used to determine net benefit obligation for 2014 and 2013 were as follows: 

	Pension benefits				OPEB
	2014		2013		2014		2013
Discount rate	3.71	%	4.55	%	3.80	%	4.60	%
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

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2014 and 2013

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

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

(b) Assumptions (continued)

The Company used the new mortality tables (RP-2014) and the mortality improvement scale (MP-2014) that were recently released by the Society of Actuaries in the current year assumptions. This change resulted in an increase to the pension and OPEB obligations of approximately U.S. $16,500.

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 2014 is as follows: 

	2014
Effect of a 1 percentage point increase in the HCCTR on:
Year-end benefit obligation	$	10,998
Total service and interest cost	623
Effect of a 1 percentage point decrease in the HCCTR on:
Year-end benefit obligation	$	(8,664	)
Total service and interest cost	(503		)

(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
	2014			2013			2014			2013
Service cost	$	4,828		$	3,273		$	2,022		$	1,602
Interest cost	8,549			4,350			2,186			1,508
Expected return on plan assets	(10,018		)	(4,160		)	(628		)	(602		)
Amortization of net actuarial loss (gain)	(346		)	23			(641		)	26
Net benefit cost	$	3,013		$	3,486		$	2,939		$	2,534

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2014 and 2013

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

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

(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	%	49.7%-78%
Debt securities	26	%	21.9%-50.3%
Other	—	%	0%-0.5%

The fair values of investments as of December 31, 2014, by asset category, are as follows:

Asset Class	Level 1	Percentage
Equity securities	122,943	72	%
Debt securities	47,771	28	%
Other	570	—	%

As of December 31, 2014, the funds do not hold any material investments in APUC. 

(e) Cash flows

The Company expects to contribute $4,289 to its pension plans and $2,021 to its post-employment benefit plans in 2015.

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

	2015		2016		2017		2018		2019		2020-2024
Pension plan	$	9,933	$	10,471	$	11,099	$	11,709	$	12,234	$	69,107
OPEB	2,157		2,416		2,697		2,908		3,060		19,472

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2014 and 2013

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

11.    Mandatorily redeemable Series C preferred shares

Effective January 1, 2013, the Company issued 100 redeemable Series C preferred shares in exchange for Class B limited partnership units issued by the St. Leon Wind Energy LP (“St. Leon LP”), a subsidiary of the Company and the legal owner of the St. Leon Wind Facility (note 18). 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 detailed below. As these shares are mandatorily redeemable for cash, they are accounted for as liabilities in the consolidated financial statements. The cumulative dividends are indexed in proportion to the increase in CPI over the term of the shares. The dividend is intended to approximate the distributions that otherwise would have accrued to holders of Class B limited partnership units. 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.

The Series C preferred shares were initially measured at their estimated fair value of $18,497 based on the present value of the expected contractual cash flows including dividends and redemption amount, discounted at a rate of 5.0%. The recognition of the initial fair value of $18,497 resulted in an adjustment to equity of the shareholders of the Company as the Class B limited partnership units had a nominal carrying amount prior to the exchange. 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:
2015	$	1,077
2016	946
2017	895
2018	1,125
2019	1,334
Thereafter to 2031	19,525
Redemption amount	5,340
	30,242
Less amounts representing interest	(11,549		)
	18,693
Less current portion	(1,085		)
	$	17,608

12. Other assets

Other assets consist of the following:

	2014		2013
Restricted cash	$	18,702	$	6,021
Deferred financing costs	10,732		9,011
Other	5,666		3,752
	$	35,100	$	18,784

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2014 and 2013

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

13. Other long-term liabilities and Deferred credits

Other long-term liabilities consist of the following: 

	2014			2013
Asset retirement obligation	$	13,884		$	9,508
Customer deposits	11,713			8,774
Provision for injury and damages	1,173			1,215
Deferred water rights inducement	2,683			2,764
Contingent consideration	1,202			1,102
Other	12,445			4,580
	43,100			27,943
Less current portion	(9,873		)	(7,451		)
	$	33,227		$	20,492

The asset retirement obligation mainly relates to legal requirements to: (i) remove wind farm facilities upon termination of land leases; (ii) cut (disconnect from the distribution system), purge (clean 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 obligation of $2,570 (2013 - $1,651) for newly constructed renewable generation facilities.

Deferred credits consist of the following:

	2014			2013
Deferred tax credit (note 20)	$	19,130		$	24,893
Deferred insurance proceeds	12,190			—
Deferred revenue	942			—
	$	32,262		$	24,893
Less: current portion	(18,638		)	(7,778		)
	$	13,624		$	17,115

Insurance proceeds received for some renewable generation facilities under repairs are deferred until they are virtually certain of being realized.

14. Shareholders’ capital

(a) Common shares

Number of common shares: 

	2014	2013
Common shares, beginning of year	206,348,985	188,763,486
Public offering (i)	29,444,000	—
Conversion and redemption of convertible debentures (ii)	—	150,816
Conversion of subscription receipts (iii)	—	15,223,016
Issuance of shares under the dividend reinvestment (iv) and employee share purchase plans ((c)(ii))	2,356,483	2,211,667
Common shares, end of year	238,149,468	206,348,985

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2014 and 2013

(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.

On April 23, 2013, the Company’s shareholders renewed its shareholders’ rights plan (the “Rights Plan”). The Rights Plan has a term of three years. 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 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)Conversion and redemption of convertible debentures

In 2013, $960 of Series 3 Debentures were redeemed for 150,816 common shares of APUC.

(iii) Subscription receipts

On December 29, 2014, the Company received total proceeds of $77,503 from the issuance to Emera of 8,708,170 subscription receipts at a price of $8.90 per share in connection with the Odell SponsorCo acquisition (note 8(a)). At any time after the earlier of commencement of operations of the Odell Wind Project or November 14, 2015, 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 after the earlier of the Park Water System acquisition or December 29, 2015, 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.

On March 26, 2013, in connection with the acquisition of the Peach State Gas system, the Company issued 3,960,000 common shares at a price of $7.40 per share for total proceeds of $29,304 pursuant to a subscription receipt agreement with Emera.

On February 14, 2013, 11,263,016 subscription receipts issued in 2012 were exercised by Emera and the Company issued 11,263,016 common shares in exchange.

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2014 and 2013

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

14. Shareholders’ capital (continued)

(a) Common shares (continued)

(iv) 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 706,680 common shares under the dividend reinvestment plan.

(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. On November 9, 2012, APUC issued 4,800,000 Series A preferred shares, at a price of $25 per share, for aggregate proceeds of $120,000 before issuance cost of $4,700 or $3,454 net of tax.

The holders of preferred shares are entitled to receive fixed cumulative preferential dividends at an annual rate of $1.125 per share, payable quarterly, as and when declared by the Board. The Series A preferred shares yield 4.5% annually for the initial six-year period up to, but excluding December 31, 2018, with the first dividend payment occurring December 31, 2012. The dividend rate will reset on December 31, 2018, and every five years thereafter at a rate equal to the then five-year Government of Canada bond yield plus 2.94%. The Series A preferred shares are redeemable at $25 per share at the option of the Company on December 31, 2018, and on December 31 of every fifth year thereafter. The holders of Series A preferred shares have the right to convert their shares into Cumulative Floating Rate preferred shares, Series B (the "Series B preferred shares”), subject to certain conditions, on December 31, 2018, and on December 31 of every fifth year thereafter. The Series B preferred shares carry the same features as the Series A preferred shares, except that holders 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%. The holders of Series B preferred shares will have the right to convert their shares back into Series A preferred shares on December 31, 2018, and on December 31 of every fifth year thereafter. The Series A preferred shares and the Series B preferred shares do not have a fixed maturity date and are not redeemable at the option of the holders thereof.

On January 1, 2013, the Company issued 100 redeemable Series C preferred shares in exchange for Class B limited partnership units issued by the St Leon LP. The mandatorily redeemable Series C preferred shares are recorded as a liability on the consolidated balance sheets (note 11).

On March 5, 2014, APUC issued 4,000,000 Series D preferred shares, at a price of $25 per share, for aggregate proceeds of $100,000 before issuance costs of $3,729 or $2,741 net of tax.

The holders of the Series D preferred shares are entitled to receive fixed cumulative preferential dividends at an annual rate of $1.25 per share, payable quarterly, as and when declared by the Board. The Series D preferred shares yield 5.0% annually for the initial five-year period up to, but excluding March 31, 2019, with the first dividend payment occurring June 30, 2014. The dividend rate will reset on March 31, 2019, and every five years thereafter at a rate equal to the then five-year Government of Canada bond yield plus 3.28%. The Series D preferred shares are redeemable at $25 per share at the option of the Company on March 31, 2019, and on March 31 of every fifth year thereafter. The holders of Series D preferred shares have the right to convert their shares into Cumulative Floating Rate preferred shares, Series E (the "Series E preferred shares”), subject to certain conditions, on March 31, 2019, and on March 31 of every fifth year thereafter. The Series E preferred shares carry the same features as the Series D preferred shares, except that holders 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 3.28%. The holders of Series E preferred shares will have the right to convert their shares back into Series D preferred shares on March 31, 2019, and on March 31 of every fifth year thereafter. The Series D preferred shares and the Series E preferred shares do not have a fixed maturity date and are not redeemable at the option of the holders thereof.

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2014 and 2013

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

14. Shareholders’ capital (continued)

(c) Share-based compensation

For the year ended December 31, 2014, APUC recorded $3,248 (2013 - $2,046) in total share-based compensation expense detailed as follows: 

	2014		2013
Stock options	$	1,931	$	1,687
Directors deferred share units	273		155
Employee share purchase	116		75
Performance share units	928		129
Total share-based compensation	$	3,248	$	2,046

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, 2014, total unrecognized compensation costs related to non-vested options and performance share unit were $2,084 and $2,380, respectively, and are expected to be recognized over a period of 1.71 years and 1.61, respectively.

(i) Stock option plan

The Company’s stock 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: 

	2014			2013
Risk-free interest rate	1.97		%	1.61		%
Expected volatility	38		%	37		%
Expected dividend yield	3.84		%	3.83		%
Expected life	8 years			8 years
Weighted average grant date fair value per option	$	2.00		$	2.00

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2014 and 2013

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

14. Shareholders’ capital (continued)

(c) Share-based compensation (continued)

(i) Stock option plan (continued)

Stock option activity during the period is as follows: 

	Number of awards	Weighted average exercise price		Weighted average remaining contractual term (years)	Aggregate intrinsic value
Balance at January 1, 2013	3,750,727	$	5.25	6.07	$	5,939
Granted	816,402	7.72		8.00	—
Balance at December 31, 2013	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
Exercisable at December 31, 2014	3,601,647	$	5.33	4.20	$	15,531

(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, 2014, a total of 93,598 common shares (2013 - 85,410) 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, 2014, 110,241 (2013 - 74,786) DSUs were outstanding pursuant to the election of the directors to defer a percentage of their director’s fee in the form of DSUs.

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2014 and 2013

(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

The Company offers a performance share unit 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 184% 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. During the second quarter, the Company settled 22,665 vested performance share units (“PSUs”) for $162 in cash. At the annual general meeting held on June 18, 2014, the shareholders approved a maximum of 500,000 common shares issuable from Treasury to settle PSUs. With the ability to issue shares from Treasury or purchase shares on the market, the Company expects to settle the remaining PSUs in common shares. As a result, the PSUs continue to be 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.

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, 2013	83,483		$	6.58	1.80	$	571
Granted	5,537		6.79		1.23	41
Exercised	(20,640	)	6.70		—	(151		)
Forfeited	(2,185	)	6.70		—	(16		)
Balance at December 31, 2013	66,195		$	6.57	0.62	$	486
Granted, including dividends	407,962		8.22		3	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	$	439
Exercisable at December 31, 2014	42,097		$	6.86	—	$	486

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2014 and 2013

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

15. Accumulated other comprehensive income (loss)

Accumulated other comprehensive income (loss) consists of the following balances, net of tax:

	Foreign currency cumulative translation			Unrealized gain (loss) on cash flow hedges			Net change on available-for-sale investments			Pension and post-employment actuarial changes			Total
Balance, January 1, 2013	$	(105,957	)	$	3,596		$	—		$	(2,506	)	$	(104,867	)
OCI before reclassifications	48,486			10,357			—			16,698			75,541
Amounts reclassified	—			(2,113		)	—			29			(2,084		)
Net current period OCI	48,486			8,244			—			16,727			73,457
Balance, December 31, 2013	$	(57,471	)	$	11,840		$	—		$	14,221		$	(31,410	)
OCI (loss) before reclassifications	65,303			6,993			519			(35,396		)	37,419
Amounts reclassified	—			5,423			(518		)	(273		)	4,632
Net current period OCI (loss)	$	65,303		$	12,416		$	1		$	(35,669	)	$	42,051
Acquisition of non-controlling interest	21,029			2,543			—			—			23,572
Balance, December 31, 2014	$	28,861		$	26,799		$	1		$	(21,448	)	$	34,213

Amounts reclassified from accumulated other comprehensive income (loss) 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.

16. Cash dividends

All dividends of the Company are made on a discretionary basis as determined by the Board. For the year ended December 31, 2014, the Company declared dividends to shareholders on common shares totaling $82,898 (2013 - $68,291) or $0.3695 per common share (2013 - $0.3325 per common share). The Board declared a dividend on the Company’s common shares of U.S. $0.0875 per share payable on January 15, 2015 to the shareholders of record on December 31, 2014.

For the year ended December 31, 2014, the Company declared and paid dividends to Series A preferred shareholders totaling $5,400 (2013 - $5,400) or $1.125 per Series A preferred share (2013 - $1.1250 per Series A preferred share).

For the year ended December 31, 2014, the Company declared and paid dividends to Series D preferred shareholders totaling $4,103 (2013 - $nil) or $1.0257 per Series D preferred share (2013 - $nil per Series D preferred share).

17. Divestitures

(a) EFW Thermal Facility

During 2013, the Company initiated a strategic review of the Company’s business plan and opportunities available for its Energy From Waste Thermal Facility (“EFW Thermal Facility”) and Brampton Cogeneration Inc. (“BCI Thermal Facility”).  As a result of the review, the Company decided to sell the facilities. In 2013, the net assets of the EFW and BCI were written down to their estimated fair value less cost of sale, which resulted in a write-down of the net assets of $56,851 before tax, or $42,538 net of tax of $14,313. The Company sold the EFW and BCI Thermal Facilities on April 4, 2014. These assets were part of the Generation: Thermal reporting segment.

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2014 and 2013

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

17. Divestitures (continued)

(b) Sale of U.S. Hydro facilities

On June 29, 2013, the Company sold 9 small U.S. hydroelectric generating facilities that were no longer considered strategic to the ongoing operations of the Company, for gross proceeds of U.S. $23,400 for a gain on sale of U.S. $960, net of tax recovery of U.S. $1,605. On June 16, 2014, the Company sold its final small U.S. hydroelectric generating facility for U.S. $3,600. These assets were part of the Generation: Renewable reporting segment.

(c) Results from discontinued operations

The assets of the EFW, BCI Thermal Facilities and the small U.S. hydroelectric generating facilities were presented as assets held for sale on the 2013 consolidated balance sheet and the operating results from these facilities are disclosed as discontinued operations in the 2014 and 2013 consolidated financial statements.

The summary of operating results and cash flows from discontinued operations for the years ended December 31 is as follows: 

	2014			2013
Non-regulated energy sales	$	2,174		$	9,327
Waste disposal fees	2,233			8,160
Other and interest income	63			336
Operating and administrative expenses	(5,284		)	(19,720		)
Foreign exchange	111			80
Depreciation of property, plant and equipment	—			(2,483		)
Interest expense	(19		)	(58		)
Gain (loss) on sale of assets	(960		)	1,016
Write-off of assets	(1,971		)	(57,160		)
Non-cash gain on sale of assets	105			—
Deposit on sale	143			—
Loss from discontinued operations, before income taxes	(3,405		)	(60,502		)
Income tax recovery	1,278			18,491
Loss from discontinued operations, net of income taxes	$	(2,127	)	$	(42,011	)
Add:
Depreciation of property, plant and equipment	—			2,483
Deposit on sale	(143		)	—
Write-off of assets	1,971			57,160
Non-cash gain on sale of assets	(105		)	—
Incurred closing costs on disposal of assets	—			(2,916		)
Contingent liability	—			(613		)
Income tax recovery	(1,278		)	(18,491		)
Cash used in discontinued operations	$	(1,682	)	$	(4,388	)

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2014 and 2013

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

17. Divestitures (continued)

(c) Results from discontinued operations (continued)

Assets held-for-sale as of December 31, were as follows: 

	2014		2013
Property, plant and equipment	$	—	$	21,193
Accounts receivable and prepaid expenses	—		2,734
Total assets held for sale, current	$	—	$	23,927

 Liabilities held for sale as of December 31, were as follows: 

	2014		2013
Accounts payable and accrued liabilities	$	—	$	1,471

18. Related party transactions

Ian Robertson and Chris Jarratt (“Senior Executives”), respectively Chief Executive Officer and Vice-Chair of APUC, are indirect shareholders of Algonquin Power Management Inc. (“APMI”), the former manager of the Company and several related affiliates (collectively, the “Parties”). Prior to 2010, there were several related party transactions and co-owned assets which existed pursuant to the external management structure before the internalization of management which occurred on December 21, 2009.

In 2011, the Board formed an independent committee (“Independent Board Committee”) and initiated a process to review all of the remaining business associations with the Parties in order to reduce and/or eliminate these relationships. The Independent Board Committee engaged independent consultants and advisors to assist with this process and to provide advice in respect thereof. Specifically, the independent advisors provided advice to the Independent Board Committee in relation to the valuations of the generating assets, tax and legal matters.

The process initiated in 2011 was completed in November 2013 and all related party transactions except as noted below, between APUC and the Parties have been addressed to the satisfaction of the Independent Board Committee and the Board as discussed below.

The following describes the business associations and resolution with APMI and Senior Executives:

Due to and from related parties

Effective December 31, 2013, APUC paid the Parties $1,829 in connection with outstanding fees and the Parties paid APUC $812 in connection with reimbursement of expenses. As at December 31, 2014, $47 (2013 - $47) remains due from Algonquin Power Systems Ltd., a corporation partially owned by the Senior Executives.

Equity interests in Rattle Brook, Long Sault, BCI

The Parties owned interests in three power generation facilities in which APUC also has an interest in. A brief description of the facilities is provided as follows:

• Rattle Brook is a 4 MW hydroelectric generating facility (“Rattle Brook”) constructed in 1998 in which APUC owned a 45% interest and Senior Executives hold an equity interest in the remaining 55%.

• Long Sault is an 18 MW hydroelectric generating facility constructed in 1997. APUC acquired its interest in Long Sault by way of subscribing to two notes from the original partners. One of the original partners; an affiliate of APMI; was entitled to receive 5% of the equity cash flows commencing in 2014.

• Brampton Cogeneration is an energy supply facility which sells steam produced by EFW.  In 2004, APMI acquired 50 Class B partnership units in BCI entitling them to 50% of the cash flow above 15% return on the investment.

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2014 and 2013

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

18. Related party transactions (continued)

Equity interests in Rattle Brook, Long Sault, BCI (continued)

Effective December 31, 2013, APUC acquired the Parties’ shares of Algonquin Power Corporation Inc. ("APC") which owns the partnership interest in the 18 MW Long Sault Rapids hydroelectric facility and the partnership interest in the Brampton cogeneration plant for an amount equal to $3,780. As APUC already consolidates Long Sault as a VIE, the acquisition of this partnership interest was treated as an equity transaction. The payment resulted in an adjustment to deferred tax liability of $10,692 in regards to tax attributes acquired with the partnership interests and an adjustment of $14,601 to equity of the shareholders of the Company as the partnership interests had a nominal carrying amount prior to the exchange.

In addition, APUC sold its 45% interest in the 4 MW Rattle Brook hydroelectric facility to the Parties for gross proceeds $3,408 for a loss on sale, net of tax of $422.

APUC earned a fee of $400 from APC during the year ended December 31, 2013 related to settlement of the related party transactions.

St. Leon LP Units

Third-party investors, including Senior Executives previously held 100 Class B limited partnership units issued by the St. Leon Limited Partnership which is the legal owner of the St. Leon Wind Facility. 

On January 1, 2013, the Company issued 100 redeemable Series C preferred shares and exchanged such shares for the 100 Class B limited partnership units (note 11) including 36 units held indirectly by Senior Executives. The Series C preferred shares provide dividends identical to what is expected from the Class B limited partnership units, as determined by independent consultants retained by the Independent Board Committee. As at January 1, 2013, no Senior Executives have any further direct or indirect ownership of the St. Leon Wind Facility.

Office Facilities

APUC has leased its head office facilities since 2001 on a triple net basis from an entity partially owned by the Senior Executives. Base lease costs for the year ended December 31, 2014 were $315 (2013 ‑ $310). In the fourth quarter of 2014, APUC moved all head office employees into new premises and terminated the related party lease for nominal consideration. There is no further related party matter in relation to an office lease.

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 an agreement to charter aircraft in which the Senior Executives have a partial ownership. During the year ended December 31, 2013, APUC reimbursed direct costs in connection with the use of the aircraft of $472. As at December 31, 2013, the Independent Board Committee and the Parties agreed that all future utilization of chartered aircraft would be undertaken through a third-party charter operator at fair market value and under arrangements in which the Senior Executives have no interest. Final arrangements in this regard had not been completed as at December 31, 2014. During the year ended December 31, 2014, APUC reimbursed direct costs in connection with the use of the aircraft of $709.

Trafalgar

The Company owns debt on seven hydroelectric facilities owned by Trafalgar Power Inc. and an affiliate (“Trafalgar”).  In 1997, Trafalgar went into default under its debt obligations and an affiliate of APMI moved to foreclose on the assets.  Subsequently Trafalgar went into bankruptcy.  APUC and the affiliate of APMI have been jointly involved in litigation and in bankruptcy proceedings with Trafalgar since 2004.  APMI initially funded $2 million in legal fees prior to 2004. 

In 2004, the Company reimbursed APMI $1 million of the total third-party legal fees (which to that point totalled $2 million), and APUC agreed to fund future legal fees, third-party costs and other liabilities. It was agreed that any net proceeds from the lawsuits would be shared proportionally to the quantum of net costs funded by each party.

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2014 and 2013

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

18. Related party transactions (continued)

Other related party transactions

A member of the Board is an executive at Emera. Related party transactions between APUC and Emera are discussed below:

• For the year ended December 31, 2014, the Company sold electricity to Maine Public Service Company (“MPS”), a subsidiary of Emera, amounting to U.S. $5,780 (2013 - U.S. $6,042). In 2011, APUC provided a corporate guarantee to MPS in an amount of U.S. $3,000 and a letter of credit in an amount of U.S. $100, primarily in conjunction with a three year contract to provide standard offer service to commercial and industrial customers in Northern Maine. For the year ended December 31, 2014, the Company purchased natural gas amounting to U.S. $5,006 (2013 - U.S. $1,304) 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.

• In 2011, APUC provided a corporate guarantee in an amount of U.S. $1,000 to a subsidiary of Emera providing lead market participant services for fuel capacity and forward reserve markets to ISO NE for the Windsor Locks facility. There has not been any transaction under this contract in the last three years.

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

Other

A spouse of one of the Senior Executives provided market research consulting services to certain subsidiaries of the Company. During the year ended December 31, 2014 APUC paid $192 (2013 - $45) in relation to these services.

19. Non-controlling interests

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

	2014			2013
Net earnings attributable to Class B partnership units of Wind Portfolio SponsorCo	$	3,484		$	9,556
Net loss attributable to Class A partnership units	(27,199		)	(20,408		)
Other net earnings attributable to non-controlling interests	1,529			39
Total net loss attributable to non-controlling interests	$	(22,186	)	$	(10,813	)

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(g)).

The non-controlling Class A membership equity investors ("Class A partnership units") of Wind Portfolio SponsorCo and of the Bakersfield Solar Project, beginning December 31, 2014 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(t).

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2014 and 2013

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

20. 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% (2013 - 26.5%). The differences are as follows:

	2014			2013
Expected income tax expense at Canadian statutory rate	$	19,199		$	16,072
Increase (decrease) resulting from:
Recognition of deferred credit	(5,763		)	(6,676		)
Effect of differences in tax rates on transactions in and within foreign jurisdictions and change in tax rates	(1,677		)	(2,338		)
Non-taxable corporate dividend	(2,618		)	(2,896		)
Non-controlling interests share of income	8,824			4,266
Production tax credit	(339		)	(247		)
Allowance for equity funds used during construction	(746		)	(694		)
State taxes	604			313
Other	(677		)	1,355
Income tax expense	$	16,807		$	9,155

For the years ended December 31, 2014 and 2013, earnings from continuing operations before income taxes consists of the following:

	2014		2013
Canadian operations	$	11,930	$	19,687
U.S. operations	60,519		40,962
	$	72,449	$	60,649

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

	Current			Deferred			Total
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
Year ended December 31, 2013
Canada	$	1,532		$	881		$	2,413
United States	994			5,748			6,742
	$	2,526		$	6,629		$	9,155

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2014 and 2013

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

20. Income taxes (continued)

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, 2014 and 2013 are presented below:

	2014			2013
Deferred tax assets:
Non-capital loss, investment tax credits, currently non-deductible interest expenses, and financing costs	$	319,056		$	226,314
Pension and OPEB	54,458			31,433
Acquisition related costs	5,168			5,152
Environmental obligation	28,555			23,076
Production tax credit	2,098			1,633
Reserves not currently deductible	2,315			2,397
Other	3,988			2,780
Total deferred income tax assets	415,638			292,785
Less valuation allowance	(15,534		)	(15,667		)
Total deferred tax assets	400,104			277,118
Deferred tax liabilities:
Property, plant and equipment	(387,931		)	(267,344		)
Intangible assets	(2,752		)	(8,321		)
Outside basis in partnership	(15,194		)	(2,210		)
Regulatory accounts	(49,399		)	(24,745		)
Financial derivatives	(15,013		)	(7,675		)
Total deferred tax liabilities	(470,289		)	(310,295		)
Net deferred tax liabilities	$	(70,185	)	$	(33,177	)

The valuation allowance for deferred tax assets as at December 31, 2014 was $(15,534) (2013 - $(15,667)). 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 carry back and carry forward periods), projected future taxable income, and tax-planning strategies in making this assessment.

Deferred income taxes are classified in the financial statements as: 

	2014			2013
Current deferred income tax asset	$	7,210		$	19,652
Non-current deferred income tax asset	57,065			86,632
Current deferred income tax liability	(3,702		)	(2,308		)
Non-current deferred income tax liability	(130,758		)	(137,153		)
	$	(70,185	)	$	(33,177	)

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2014 and 2013

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

20. Income taxes (continued)

As of December 31, 2014, the Company had non-capital losses carry forwards available to reduce future year’s taxable income, which expire as follows: 

Year of expiry	Non-capital loss carryforwards
2015	$	5,426
2016 and onwards	733,022
	$	738,448

On October 27, 2009, unitholders of Algonquin Power Income Fund exchanged their trust units on a one-for-one basis for common shares of APUC (the “Unit Exchange Transaction”). As a result of the Unit Exchange Transaction, APUC recorded certain additional tax attributes to the extent management believed they were more likely than not to be realized. The excess of the carrying amount of the tax attributes assumed over the consideration paid was recorded as a deferred credit of $55,647 on the date of the Unit Exchange Transaction (the “Transaction Date”). The deferred credit has been recognized into income as a deferred income tax recovery in relative proportion to the amount of the related tax attributes that have been utilized since the Transaction Date.

Subsequent to the balance sheet date, APUC received a proposal letter from the Canada Revenue Agency (“CRA”) which outlines its intention to challenge the tax consequences of the Unit Exchange Transaction. CRA is seeking to apply the acquisition of control rules or the general anti-avoidance rules of the Income Tax Act (Canada) the effect of which would be to deny APUC of the benefit of the tax attributes assumed as part of the Unit Exchange Transaction.

Should APUC receive a Notice of Reassessment covering the 2009, 2010, 2011, 2012 and 2013 taxation years, APUC will be required to make a deposit payment of 50% of the tax liability (including interest and any applicable penalties) claimed by the CRA in order to appeal the expected reassessment. Based on the tax amounts related to the 2009 to 2013 taxation years, that payment amount would be approximately $17,500. Additionally, assuming 2014 return will be similarly reassessed, a further payment of approximately $3,100 would also be required. APUC would also be required to make a deposit payment of 50% of the taxes the CRA claims are owed in any future tax year if the CRA were to issue a similar Notice of Reassessment for such years and APUC were to appeal it.

Should APUC be successful in defending its position, all such payments plus applicable interest, will be refunded to APUC. If the CRA is successful, APUC would be required to pay the balance of the taxes assessed, plus interest and penalties.

APUC remains confident in the appropriateness of its tax filing position and the expected tax consequences of the Unit Exchange Transaction and intends to vigorously defend such position. APUC strongly believes that the acquisition of control or the general anti-avoidance rules do not apply to the Unit Exchange Transaction and intends to file its future tax returns on a basis consistent with its previous tax returns. As a result, the probability of any potential final cash payment and impact on net earnings cannot be estimated at this time, but could range from $nil to $45,000.

The impact of the proposal on APUC’s tax provision has been considered by management; however, management continues to believe that the most likely outcome has not changed and it is more likely than not, that APUC will be successful in defending its position. On this basis, APUC’s 2014 financial statements do not include the impact of a potential reassessment. Until the matter is resolved with CRA, or should new facts arise that would result in a change to management’s assessment of the most likely outcome, any future deposit tax payments made by APUC will be recorded to the consolidated balance sheets and will not impact net earnings.

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2014 and 2013

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

21. 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 outstanding and subscription receipts issued (note 14 (a)(iii)) during the year. Diluted net earnings per share is computed using the weighted-average number of common shares, subscription receipts issued, additional shares issued subsequent to year-end under the dividend reinvestment plan, PSUs and DSUs outstanding during the period and, if dilutive, potential incremental common shares issuable upon the exercise of stock options. The dilutive effect of outstanding stock options is reflected in diluted earnings per share by application of the treasury stock method.

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:

	2014			2013
Net earnings attributable to shareholders of APUC	$	75,701		$	20,296
Series A Preferred shares dividend	5,400			5,400
Series D Preferred shares dividend	4,103			—
Net earnings attributable to common shareholders of APUC	$	66,198		$	14,896
Discontinued operations	(2,127		)	(42,011		)
Net earnings attributable to common shareholders of APUC from continuing operations - Basic and Diluted	$	68,325		$	56,907
Weighted average number of shares
Basic	213,953,870			204,350,689
Effect of dilutive securities	2,387,722			1,482,515
Diluted	216,341,592			205,833,204

The shares potentially issuable as a result of 1,786,401 stock options (2013 – 885,418) are excluded from this calculation as they are anti-dilutive.

22. Segmented information

During the fourth quarter, the Company aligned its management reporting under three business units - Generation, Transmission and Distribution. As a result, APUC has four reporting segments. Under Generation, the Company owns or has interests in hydroelectric, solar and wind power facilities which are aggregated as the renewable segment and operates co-generation, steam production and other thermal facilities which are aggregated as the thermal segment. The Distribution reporting segment now aggregates the electric, natural gas and water distribution utilities into a single reporting segment. Finally, the Transmission reporting segment, invests in rate regulated electric transmission and natural gas pipeline systems.

The operating segments were aggregated as generation (renewable, thermal), distribution and transmission based on their economic characteristics. The Transmission segment includes the new equity method investment in the Natural Gas Pipeline Development (note 8(b)) which is not yet significant and as a result is not presented separately in the tables below.

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 new segments are reflected in the tables below. The comparative information for 2013 has been reclassified to conform with the composition of the reporting segments presented in the current year.

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2014 and 2013

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

22. Segmented information (continued)

	Year ended December 31, 2014
	Generation									Distribution			Corporate			Total
	Renewable			Thermal			Total
Revenue
Regulated electricity distribution	$	—		$	—		$	—		$	206,667		$	—		$	206,667
Regulated gas distribution	—			—			—			446,025			—			446,025
Regulated water reclamation and distribution	—			—			—			66,419			—			66,419
Non-regulated energy sales	159,400			42,900			202,300			—			—			202,300
Other revenue	13,257			3,208			16,465			5,684			—			22,149
Total revenue	172,657			46,108			218,765			724,795			—			943,560
Operating expenses	46,077			9,405			55,482			180,442			60			235,984
Regulated electricity purchased	—			—			—			120,506			—			120,506
Regulated gas purchased	—			—			—			261,116			—			261,116
Non-regulated energy purchased	16,676			22,588			39,264			—			—			39,264
	109,904			14,115			124,019			162,731			(60		)	286,690
Administrative expenses	(13,120		)	(337		)	(13,457		)	(19,947		)	(1,288		)	(34,692		)
Depreciation of property, plant and equipment	(48,479		)	(5,980		)	(54,459		)	(52,387		)	(2,128		)	(108,974		)
Amortization of intangible assets	(2,979		)	(891		)	(3,870		)	(756		)	—			(4,626		)
Other amortization	81			—			81			(528		)	—			(447		)
Gain on foreign exchange	—			—			—			—			1,112			1,112
Interest expense	(32,117		)	(1,751		)	(33,868		)	(27,139		)	(1,411		)	(62,418		)
Interest, dividend income and other income	1,683			(496		)	1,187			3,369			3,202			7,758
Gain on sale of asset	110			326			436			—						436
Acquisition-related costs	—			—			—			—			(2,552		)	(2,552		)
Write-down of long-lived assets	—			(698		)	(698		)	(300		)	(7,465		)	(8,463		)
Gain (loss) on derivative financial instruments	214			—			214			—			(1,589		)	(1,375		)
Earnings from continuing operations before income taxes	15,297			4,288			19,585			65,043			(12,179		)	72,449
Loss from discontinued operations before income taxes	(3,189		)	(216		)	(3,405		)	—			—			(3,405		)
Earnings (loss) before income taxes	$	12,108		$	4,072		$	16,180		$	65,043		$	(12,179	)	$	69,044
Property, plant and equipment	$	1,602,465		$	85,000		$	1,687,465		$	1,531,166		$	59,791		$	3,278,422
Equity-method investees	2,267			1,253			3,520			1,563			1,652			6,735
Total assets	1,795,757			100,603			1,896,360			2,106,638			111,417			4,114,415
Capital expenditures	197,051			4,012			201,063			176,849			54,461			432,373
Acquisition of operating entities	—			—			—			8,757			—			8,757

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2014 and 2013

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

22. Segmented information (continued)

	Year ended December 31, 2013
	Generation									Distribution			Corporate			Total
	Renewable Energy			Thermal Energy			Total
Revenue
Regulated electricity distribution	$	—		$	—		$	—		$	166,156		$	—		$	166,156
Regulated gas distribution	—			—			—			260,424			—			260,424
Regulated water reclamation and distribution	—			—			—			57,350			—			57,350
Non-regulated energy sales	145,661			34,530			180,191			—			—			180,191
Other revenue	7,058			2,442			9,500			1,270			400			11,170
Total revenue	152,719			36,972			189,691			485,200			400			675,291
Operating expenses	40,282			8,514			48,796			131,550			—			180,346
Regulated electricity purchased	—			—			—			97,376			—			97,376
Regulated gas purchased	—			—			—			148,784			—			148,784
Non-regulated energy purchased	8,684			17,151			25,835			—			—			25,835
	103,753			11,307			115,060			107,490			400			222,950
Administrative expenses	(13,094		)	(223		)	(13,317		)	(7,477		)	(2,724		)	(23,518		)
Depreciation of property, plant and equipment	(45,122		)	(5,439		)	(50,561		)	(41,417		)	—			(91,978		)
Amortization of intangible assets	(2,652		)	(856		)	(3,508		)	(692		)	—			(4,200		)
Other amortization	81			—			81			78			—			159
Gain on foreign exchange	—			—			—			—			567			567
Interest expense	(27,472		)	(1,046		)	(28,518		)	(23,734		)	(1,174		)	(53,426		)
Interest, dividend income and other income	1,867			193			2,060			3,228			2,497			7,785
Loss on sale of asset	(750		)	—			(750		)	—			—			(750		)
Acquisition-related costs	—			—			—			—			(2,140		)	(2,140		)
Gain (loss) on derivative financial instruments	(767		)	—			(767		)	—			5,967			5,200
Earnings from continuing operations before income taxes	15,844			3,936			19,780			37,476			3,393			60,649
Loss from discontinued operations before income taxes	1,128			(61,630		)	(60,502		)	—			—			(60,502		)
Earnings (loss) before income taxes	$	16,972		$	(57,694	)	$	(40,722	)	$	37,476		$	3,393		$	147
Property, plant and equipment	$	1,364,843		$	79,828		$	1,444,671		$	1,264,033		$	—		$	2,708,704
Equity-method investees	—			1,718			1,718			325			8,623			10,666
Total assets	1,492,144			116,922			1,609,066			1,673,631			193,784			3,476,481
Capital expenditures	46,885			2,631			49,516			108,861			—			158,377
Acquisition of operating entities	2,083			—			2,083			236,931			—			239,014

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2014 and 2013

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

22. Segmented information (continued)

Operational segments (continued)

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 2014 or 2013: Hydro Québec 11% (2013 - 14%) and Manitoba Hydro 13% (2013 - 14%). 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:

	2014		2013
Revenue
Canada	$	92,267	$	65,380
United States	851,293		609,911
	$	943,560	$	675,291
Property, plant and equipment
Canada	$	590,580	$	433,153
United States	2,687,842		2,275,551
	$	3,278,422	$	2,708,704
Intangible assets
Canada	$	25,601	$	26,802
United States	28,410		27,614
	$	54,011	$	54,416

Revenues are attributed to the two countries based on the location of the underlying generating and utility facilities.

23. 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 financial statements at the time it is concluded that its occurrence is probable and the related liability is estimable.

(i) 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 $6,400. 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.

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2014 and 2013

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

23. Commitments and contingencies (continued)

(a) Contingencies (continued)

(ii) The normal ongoing operations and historic activities of the Company are subject to various federal, state and local environmental laws and regulations and are regulated by agencies such as the United States Environmental Protection Agency, the New Hampshire Department of Environmental Services and the Massachusetts Department of Environmental Protection.

Like most other industrial companies, the gas and electric distribution utilities generate some hazardous wastes. Under federal and state laws, potential liability for historic contamination of property may be imposed on responsible parties jointly and severally, without fault, even if the activities were lawful when they occurred. In the case of regulated utilities, these costs are often allowed in rate case proceedings to be recovered from rate payers over a specified period.

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 believes that obligations imposed on it because of those sites will not have a material impact on its results of operations.

The Company estimates the remaining undiscounted, unescalated cost of these MGP-related environmental cleanup activities will be $72,594 which at discount rates ranging from 2.1% to 3.4% represents the recorded accrual of $72,305 as of December 31, 2014 (December 31, 2013 - $69,555).

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, 2014, the Company has reflected a regulatory asset of $102,735 (December 31, 2013 - $85,029) for the MGP and related sites (note 7(a)).

Estimated cash flows for site investigation and remediation costs in the next five years and thereafter are as follows: 

2015	$	19,643
2016	22,229
2017	14,394
2018	5,443
2019	629
Thereafter to 2046	10,256
	$	72,594

(b) Commitments

In addition to the commitments related to the proposed acquisitions and development projects disclosed in notes 3 and 8, the following significant commitments exist as of December 31, 2014.

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 $7,900 over a period of five years related to compliance with the legislation.

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2014 and 2013

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

23. Commitments and contingencies (continued)

(b) Commitments (continued)

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
Purchased power	$	118,158	$	—	$	—	$	—	$	—	$	—	$	118,158
Gas delivery, service and supply agreements	52,848		37,714		30,318		27,718		27,625		88,234		264,457
Service agreements	28,572		32,147		32,537		31,556		31,382		481,061		637,255
Capital projects	21,972		—		—		—		—		—		21,972
Operating leases	5,647		4,951		4,604		4,274		4,190		97,421		121,087
Total	$	227,197	$	74,812	$	67,459	$	63,548	$	63,197	$	666,716	$	1,162,929

Calpeco Electric System has entered into a five-year all-purpose power purchase agreement with NV Energy to provide its full electric requirements at NV Energy’s “system average cost” rates. The PPA has an effective starting date of January 1, 2011 with a five-year renewal option. The commitment amounts included in the table above are based on market prices as of December 31, 2014. However, the effects of purchased power unit cost adjustments are mitigated through a purchased power rate-adjustment mechanism. Granite State Electric System has several types of contracts for the purchase of electric power. Substantially all of these contracts require power to be delivered before the Company is obligated to make payment.

24. Non-cash operating items

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

	2014			2013
Accounts receivable	$	2,572		$	(213	)
Prepaid expenses	36			(11		)
Accrued liabilities	(1,346		)	260
	$	1,262		$	36

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

	2014			2013
Accounts receivable	$	(23,640	)	$	(49,888	)
Related party balances	—			(996		)
Natural gas in storage	(5,942		)	(6,330		)
Supplies and consumable inventory	(3,861		)	(525		)
Income taxes receivable	(189		)	177
Prepaid expenses	827			(485		)
Accounts payable	54,299			(29,292		)
Accrued liabilities	32,520			37,023
Current income tax liability	(1,527		)	1,399
Net regulatory assets and liabilities	(54,277		)	1,098
	$	(1,790	)	$	(47,819	)

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2014 and 2013

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

25. Financial instruments

(a) Fair value of financial instruments

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 liabilities	$	1,280,023	$	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 swap 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	$	1,343,987	$	1,427,414	$	520,142	$	907,272	$	—

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2014 and 2013

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

25. Financial instruments (continued)

(a)Fair value of financial instruments (continued)

2013	Carrying amount		Fair Value		Level 1		Level 2		Level 3
Notes receivable	$	22,678	$	26,321	$	—	$	26,321	$	—
Derivative financial instruments:
Energy contracts designated as a cash flow hedge	31,971		31,971		—		—		31,971
Energy contracts not designated as a cash flow hedge	3,737		3,737		—		—		3,737
Cross-currency swap designated as a net investment hedge	109		109		—		109		—
Commodity contracts for regulatory operations	482		482		—		482		—
Total derivative financial instruments	36,299		36,299		—		591		35,708
Total financial assets	$	58,977	$	62,620	$	—	$	26,912	$	35,708
Long-term liabilities	$	1,255,588	$	1,261,340	$	296,986	$	964,354	$	—
Preferred shares, Series C	18,805		18,293				18,293		—
Derivative financial instruments:
Energy contracts designated as a cash flow hedge	4,781		4,781		—		—		4,781
Cross-currency swap designated as a net investment hedge	7,947		7,947		—		7,947		—
Interest rate swaps not designated as a hedge	3,180		3,180		—		3,180		—
Commodity contracts for regulated operations	313		313		—		313		—
Total derivative financial instruments	16,221		16,221		—		11,440		4,781
Total financial liabilities	$	1,290,614	$	1,295,854	$	296,986	$	994,087	$	4,781

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2014 and 2013

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

25. 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, 2014 and 2013 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 liabilities 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 Red Lily conversion option is measured at fair value on a recurring basis using unobservable inputs (level 3). The fair value is based on an income approach using an option pricing model that includes various inputs such as energy yield function from wind, estimated cash flows and a discount rate of 9.0%. The Company used a discount rate believed to be most relevant given the business strategy. There was no change in fair value of $nil during the years ended December 31, 2014 or 2013.

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 $16.62 to $113.93 with a weighted average of $39.72 as of December 31, 2014.  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 are detailed in notes 25(b)(ii) and 25(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, 2014 or 2013.

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2014 and 2013

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

25. Financial instruments (continued)

(b) Derivative instruments

Derivative instruments are recognized on the consolidated balance sheets as either assets or liabilities and measured at fair value 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 sales prices to regulated customers.

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

	2014
Financial contracts: Gas swaps	1,774,018
Gas options	907,758
	2,681,776

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(d)). 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. 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: 

		2014			2013
Regulatory assets:
Gas swap contracts	U.S.	$	2,178	U.S.	$	86
Gas option contracts	U.S.	$	346	U.S.	$	208
Regulatory liabilities:
Gas swap contracts	U.S.	$	—	U.S.	$	416
Gas option contracts	U.S.	$	—	U.S.	$	37

(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)
98,167	December 2016	$	67.91	AESO
915,428	December 2022	U.S. $	42.81	PJM Western HUB
3,907,711	December 2022	U.S. $	30.25	NI HUB
4,330,303	December 2027	U.S. $	36.46	ERCOT North HUB

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 $4,684 for the year ended December 31, 2014, which is recorded in OCI.

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2014 and 2013

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

25. Financial instruments (continued)

(b) Derivative instruments (continued)

(ii) Cash flow hedges (continued)

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

	2014			2013
Effective portion of cash flow hedge, loss	$	1,043		$	18,940
Amortization on cash flow hedge	(32		)	(30		)
Loss (gain) reclassified from AOCI into non-regulated energy sales	5,423			(1,602		)
	$	6,434		$	17,308
Less non-controlling interest	5,982			(9,064		)
Change in OCI attributable to shareholders of APUC	$	12,416		$	8,244

The Company expects $10,132 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.

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

The Company periodically uses a combination of foreign exchange forward contracts and spot purchases to manage its foreign exchange exposure on cash flows generated from the U.S. operations. 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.

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 $28,537 (2013 - loss of $5,771) was recorded in OCI in 2014.

(iv) Other derivatives

The Company provides energy requirements to various customers under contracts at fixed rates. While the production from the Tinker Assets 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.

Notional quantity (MW-hrs)	Expiry	Receive average prices (per MW-hr)		Net Asset
18,283	March 2015	U.S. $	57.53	$	417

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2014 and 2013

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

25. Financial instruments (continued)

(b) Derivative instruments (continued)

(iv) Other derivatives (continued)

The Company is party to an interest rate swap whereby, the Company pays a fixed interest rate of 4.47% on a notional amount of $60,513 and receives floating interest at 90 day CDOR, up to the expiry of the swap in September 2015. As of December 31, 2014, the estimated fair value of the interest rate swap was a liability of $1,383 (2013 – liability of $3,180).  This interest rate swap is not being accounted for as a hedge and consequently, changes in fair value are recorded in earnings as they occur.

For derivatives that are not designated as cash flow 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.

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

	2014			2013
Change in unrealized loss (gain) on derivative financial instruments:
Interest rate swaps	$	(1,797	)	$	(1,598	)
Energy derivative contracts	3,386			(3,809		)
Total change in unrealized loss (gain) on derivative financial instruments	$	1,589		$	(5,407	)
Realized loss (gain) on derivative financial instruments:
Interest rate swaps	1,962			2,024
Energy derivative contracts	(3,627		)	(466		)
Total realized loss (gain) on derivative financial instruments	$	(1,665	)	$	1,558
Gain on derivative financial instruments not accounted for as hedges	(76		)	(3,849		)
Ineffective portion of derivative financial instruments accounted for as hedges	1,451			(1,351		)
Loss (gain) on derivative financial instruments	$	1,375		$	(5,200	)

(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, liquidity risk, foreign currency risk and interest rate risk, and how the Company manages those risks.

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2014 and 2013

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

25. Financial instruments (continued)

(c) Risk management (continued)

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 in Canada all of which have a credit rating of A or better. The Company does not consider the risk associated with 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 utilities, electric utilities and gas utilities in the United States. In this regard, the credit risk related to Distribution Group accounts receivable balances of U.S. $119,866 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.

As of December 31, 2014, the Company’s maximum exposure to credit risk for these financial instruments was as follows: 

	December 31, 2014
	Canadian $		US $
Cash and cash equivalents and restricted cash	$	5,823	$	19,095
Accounts receivable	20,320		151,265
Allowance for doubtful accounts	—		(6,232		)
Notes receivable	21,901		15,179
	$	48,044	$	179,307

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 our 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.

As of December 31, 2014, an amount receivable under the derivatives for Sandy Ridge, Senate and Minonk Wind Facilities of $156 (2013 - $7,344) was held as collateral by the counterparty.

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2014 and 2013

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

25. Financial instruments (continued)

(c) Risk management (continued)

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, 2014, in addition to cash on hand of $9,273 the Company had $485,927 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	$	9,130	$	90,955	$	218,795	$	961,143	$	1,280,023
Advances in aid of construction	1,149		—		—		79,955		81,104
Interest on long-term debt	64,232		125,268		102,070		146,689		438,259
Purchase obligations	267,914								267,914
Environmental obligation	19,643		36,623		6,072		10,256		72,594
Derivative financial instruments:
Cross-currency swap	1,463		2,975		2,433		29,405		36,276
Interest rate forwards	—		—		4,684		—		4,684
Interest rate swaps	1,383		—		—		—		1,383
Energy derivative and commodity contracts	2,337		591		—		—		2,928
Other obligations	9,873		860		25		29,659		40,417
Total obligations	$	377,124	$	257,272	$	334,079	$	1,257,107	$	2,225,582

Foreign currency risk

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.

The Company designates the amounts drawn on the Generation Group's revolving credit facility denominated in U.S. dollars as a hedge of the foreign currency exposure of its net investment in the Generation Group’s U.S. operations. The foreign currency transaction gain or loss on the outstanding U.S. dollar denominated balance of the facility that is designated as a hedge of the net investment in its foreign operations is reported in the same manner as a translation adjustment (in OCI) related to the net investment, to the extent it is effective as a hedge. A foreign currency loss of $2,727 for the year-ended December 31, 2014 (2013 - $1,607) was recorded in OCI.

Interest rate risk

The Company is exposed to interest rate fluctuations related to certain of its floating rate debt obligations, 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 does not currently hedge that risk.

26. Comparative figures

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