Algonquin Power & Utilities 40F 2012 Annual report | AQN Filing

Exhibit 99.2

Consolidated Financial Statements of

Algonquin Power & Utilities Corp.

For the years ended December 31, 2012 and 2011

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, 2012, based on the framework established inInternal Control–Integrated Frameworkissued 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 at December 31, 2012.

During the year ended December 31, 2012, APUC acquired Granite State Electric Company, EnergyNorth Natural Gas Inc., Liberty Energy (Midstates) Corp. and Wind Portfolio SponsorCo LLC associated with total assets of $757.7 million and total revenues of $117.0 million included in the consolidated financial statements of the Company as of and for the year ended December 31, 2012. As permitted by National Instrument 52-109 and the U.S. Securities and Exchange Commission, Management excluded these acquisitions from its evaluation of the effectiveness of the Company’s internal controls over financial reporting as of December 31, 2012 due to the complexity associated with assessing internal controls during integration efforts and the proximity of certain of the acquisitions to year-end.

March 14, 2013


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



KPMG LLP
Chartered Accountants	Telephone	(416) 777-8500
Bay Adelaide Centre	Fax	(416) 777-8818
333 Bay Street, Suite 4600	Internet	www.kpmg.ca
Toronto, Ontario M5H 2S5
Canada

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholders of Algonquin Power & Utilities Corp.

We have audited the accompanying consolidated balance sheets of Algonquin Power & Utilities Corp. as of December 31, 2012 and December 31, 2011, and the related consolidated statements of operations, comprehensive income (loss), equity and cash flows for the years then ended. 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 plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Algonquin Power & Utilities Corp. as of December 31, 2012 and December 31, 2011, and its consolidated results of operations and its consolidated cash flows for the years then ended in conformity with US generally accepted accounting principles

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, 2012, based on the criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated March 14, 2013 expressed an unqualified (unmodified) opinion on the effectiveness of Algonquin Power & Utilities Corp.’s internal control over financial reporting.

/s/ KPMG LLP

Chartered Accountants, Licensed Public Accountants

Toronto, Canada

March 14, 2013



KPMG LLP
Chartered Accountants	Telephone	(416) 777-8500
Bay Adelaide Centre	Fax	(416) 777-8818
333 Bay Street, Suite 4600	Internet	www.kpmg.ca
Toronto, Ontario M5H 2S5
Canada

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

We have audited Algonquin Power & Utilities Corp.’s internal control over financial reporting as of December 31, 2012, based on criteria established inInternal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. 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 under the heading Internal Controls over Financial Reporting in Management’s Discussion and Analysis for the year ended December 31, 2012. Our responsibility is to express an opinion on the Company’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, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

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

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

In our opinion, Algonquin Power & Utilities Corp. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012, based on criteria established inInternal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

Algonquin Power & Utilities Corp. acquired Granite State Electric Company, EnergyNorth Natural Gas Inc., Liberty Energy (Midstates) Corp., Wind Portfolio SponsorCo LLC and Wind Portfolio Holdings LLC during 2012, and management excluded from its assessment of the effectiveness of Algonquin Power & Utilities Corp.’s internal control over financial reporting as of December 31, 2012, Granite State Electric Company, EnergyNorth Natural Gas Inc., Liberty Energy (Midstates) Corp., Wind Portfolio SponsorCo LLC and Wind Portfolio Holdings LLC’s internal control over financial reporting associated with total assets of $757.7 million and total revenues of $117.0 million included in the consolidated financial statements of Algonquin Power & Utilities Corp. and subsidiaries as of and for the year ended December 31, 2012. Our audit of internal control over financial reporting of Algonquin Power & Utilities Corp. also excluded an evaluation of the internal control over financial reporting of Granite State Electric Company, EnergyNorth Natural Gas Inc., Liberty Energy (Midstates) Corp., Wind Portfolio SponsorCo LLC and Wind Portfolio Holdings LLC.

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, 2012 and December 31, 2011, and the related consolidated statements of operations, comprehensive income (loss), equity and cash flows for the years ended December 31, 2012 and December 31, 2011, and our report dated March 14, 2013 expressed an unqualified (unmodified) opinion on those consolidated financial statements.

/s/ KPMG LLP

Chartered Accountants, Licensed Public Accountants

Toronto, Canada

March 14, 2013

Algonquin Power & Utilities Corp.

Consolidated Balance Sheets


(thousands of Canadian dollars)
	December 31, 2012		December 31, 2011
ASSETS
Current assets:
Cash and cash equivalents	$	53,122	$	72,887
Accounts receivable, net of allowance for doubtful accounts of $4,360 and $385 (note 4)		90,361		44,113
Natural gas in storage (note 1(g))		19,279		—
Supplies and consumables inventory		4,233		2,714
Regulatory assets (note 7)		10,644		2,458
Due from related parties (note 19)		816		2,275
Prepaid expenses		10,886		5,620
Notes receivable (note 8)		537		482
Deferred tax asset (note 17)		10,567		13,022
Income tax receivable (note 17)		556		133
Derivative instruments (note 24)		7,020		—
Assets held for sale (note 18)		24,390		25,847
Other current assets (note 12)		833		833

		233,244		170,384

Property, plant and equipment (note 5)		2,162,715		920,109
Intangible assets (note 6)		56,781		55,269
Goodwill		61,459		9,710
Regulatory assets (note 7)		123,748		2,571
Derivative instruments (note 24)		6,230		—
Long-term investments and notes receivable (note 8)		37,646		39,820
Deferred non-current income tax asset (note 17)		77,497		67,671
Other assets (note 12)		18,917		16,773

	$	2,778,237	$	1,282,307

Algonquin Power & Utilities Corp.

Consolidated Balance Sheets


(thousands of Canadian dollars)
	December 31, 2012			December 31, 2011
LIABILITIES AND EQUITY

Current liabilities:
Accounts payable	$	34,283		$	8,382
Accrued liabilities		99,468			46,821
Due to related parties (note 19)		1,811			1,795
Dividends payable (note 16)		15,498			9,566
Regulatory liabilities (note 7)		6,065			2,469
Long term liabilities (note 9)		1,768			1,624
Other long term liabilities (note 13)		4,352			1,037
Advances in aid of construction (note 1(o))		591			604
Derivative instruments (note 24)		2,211			2,935
Income tax liability (note 17)		539			407
Deferred credits (note 17)		5,754			6,314
Deferred income tax liability (note 17)		1,133			723

		173,473			82,677
Long-term liabilities (note 9)		769,058			331,092
Convertible debentures (note 10)		960			122,297
Advances in aid of construction (note 1(o))		71,626			74,547
Regulatory liabilities (note 7)		82,050			19,184
Deferred income tax liability (note 17)		100,798			53,231
Derivative instruments (note 24)		15,605			5,209
Deferred credits (note 17)		25,816			30,348
Pension and post employment benefits (note 11)		59,246			—
Environmental obligation (note 21)		56,587			—
Other long-term liabilities (note 13)		20,889			11,027

		1,202,635			646,935
Equity:
Preferred shares (note 14(b))		116,546			—
Common shares (note 14(a))		1,245,326			975,263
Subscription receipts (note 14(a)(iii))		61,160			—
Additional paid-in capital (note 14)		5,224			1,525
Deficit		(406,143	)		(366,080	)
Accumulated other comprehensive loss (note 15)		(104,867	)		(96,510	)


Total Equity attributable to shareholders of Algonquin Power & Utilities Corp.		917,246			514,198
Non-controlling interests		484,883			38,497

Total Equity		1,402,129			552,695

Commitments and contingencies (note 21)
Subsequent events (notes 3,10, 14, 18 and 25)

	$	2,778,237		$	1,282,307

See accompanying notes to consolidated financial statements

Algonquin Power & Utilities Corp.

Consolidated Statements of Operations


(thousands of Canadian dollars, except per share amounts)
	2012			2011
Revenue:

Regulated electricity sales and distribution	$	108,457		$	77,368
Regulated gas sales and distributions		75,718			—
Regulated water reclamation and distribution		46,423			44,989
Non-regulated energy sales		121,150			128,311
Waste disposal fees		14,288			16,406
Other revenue		3,851			3,643

		369,887			270,717

Expenses

Operating		130,333			84,018
Regulated electricity purchased		68,209			46,508
Regulated gas purchased		37,461			—
Non-regulated fuel for generation		14,589			24,628
Depreciation of property, plant and equipment		50,382			37,988
Amortization of intangible assets		4,151			6,433
Administrative expenses		19,608			17,534
Write down of long-lived assets		—			15,166
Gain on foreign exchange		(561	)		(652	)

		324,172			231,623

Operating income from continuing operations		45,715			39,094

Interest expense		35,941			30,437
Interest, dividend income and other income		(7,239	)		(5,659	)
Acquisition-related costs		7,709			2,965
Loss/(gain) on derivative financial instruments (note 24(b))		(233	)		5,844

		36,178			33,587

Earnings from continuing operations before income taxes		9,537			5,507

Income tax expense (recovery) (note 17)
Current		738			300
Deferred		(14,304	)		(22,847	)

		(13,566	)		(22,547	)


Earnings from continuing operations		23,103			28,054

Loss from discontinued operations net of tax (note 18)		(1,157	)		(752	)

Net earnings		21,946			27,302
Net earnings attributable to non-controlling interests		7,414			3,921


Net earnings attributable to shareholders of Algonquin Power & Utilities Corp.	$	14,532		$	23,381

Basic net earnings per share from continuing operations (note 20)	$	0.10		$	0.21
Basic net loss per share from discontinued operations (note 20)		(0.01	)		(0.01	)
Basic net earnings per share (note 20)		0.09			0.20

Diluted net earnings per share from continuing operations (note 20)		0.10			0.21
Diluted net loss per share from discontinued operations (note 20)		(0.01	)		(0.01	)
Diluted net earnings per share (note 20)	$	0.09		$	0.20

See accompanying notes to consolidated financial statements

Algonquin Power & Utilities Corp.

Consolidated Statements of Comprehensive Income (Loss)


(thousands of Canadian dollars)
	2012			2011
Net earnings	$	21,946		$	27,302
Other comprehensive income (loss):
Foreign currency translation adjustment, net of tax of $560 and ($Nil), respectively (notes 1(v), 9 and 24(c))		(7,829	)		4,272
Change in fair value of cash flow hedge, net of tax of $1,715 and $Nil, respectively (note 24(b) and (ii))		3,593			—
Change in unrealized pension and other post-retirement expense, net of tax of $1,653 and $Nil, respectively (note 11)		(2,453	)		(48	)

Other comprehensive income (loss), net of tax		(6,689	)		4,224

Comprehensive income		15,257			31,526
Comprehensive income attributable to the non-controlling interest		9,083			4,810

Comprehensive income attributable to shareholders of Algonquin Power & Utilities Corp.	$	6,174		$	26,716

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, 2012:
	Common		Preferred		Subscription		Additional paid-in			Accumulated			Accumulated			Non- controlling
	Shares		Shares		Receipts		capital			Deficit			OCI			interests			Total
Balance, December 31, 2011	$	975,263	$	—	$	—	$	1,525		$	(366,080	)	$	(96,510	)	$	38,497		$	552,695
Net earnings											14,532						7,414			21,946
Other comprehensive loss		—		—		—		—			—			(8,357	)		1,668			(6,689	)
Dividends declared and distributions to non-controlling interests		—		—		—		—			(43,619	)		—			(2,640	)		(46,259	)
Dividends and issuance of shares under dividend reinvestment plan		7,343		—		—		—			(7,343	)		—			—			—
Exercise and conversion of subscription receipts		142,609		—		—		—			—			—			—			142,609
Issuance of subscription receipts		—		—		61,160		—			—			—			—			61,160
Conversion and redemption of convertible debentures		118,779		—		—		(689	)		—			—			—			118,090
Issuance of common shares under employee share purchase plan		432		—		—		—			—			—			—			432
Stock compensation expense		—		—		—		1,956			—			—			—			1,956
Public offering related taxes		900						—			—			—			—			900
Issuance of preferred shares		—		116,546		—		—			—			—			—			116,546
Acquisition of 49.99% of Liberty Energy (California)		—		—		—		—			(3,633	)					(35,023	)		(38,656	)
Acquisition of U.S. Wind farms		—		—		—		2,432			—			—			474,967			477,399

Balance, December 31, 2012	$	1,245,326	$	116,546	$	61,160	$	5,224		$	(406,143	)	$	(104,867	)	$	484,883		$	1,402,129

Algonquin Power & Utilities Corp.

Consolidated Statement of Equity

(thousands of Canadian dollars)


For the year ended December 31, 2011:
	Common		Preferred		Subscription		Additional paid-in			Accumulated			Accumulated			Non- controlling
	Shares		Shares		Receipts		capital			Deficit			OCI (CTA)			interests			Total
Balance, December 31, 2010	$	795,329	$	—	$	—	$	1,612		$	(357,035	)	$	(99,845	)	$	—		$	340,061
Net earnings											23,381						3,921			27,302
Other comprehensive income		—		—		—		—			—			3,335			889			4,224
Dividends declared and distributions to non-controlling interests		—		—		—		—			(32,426	)		—			(523	)		(32,949	)
Conversion and redemption of convertible debentures		59,973		—		—		(815	)		—			—			—			59,158
Public offering		91,188		—		—		—			—			—			—			91,188
Exercise and conversion of subscription receipts		27,700		—		—		—			—			—			—			27,700
Stock compensation expense		—		—		—		728			—			—			—			728
Acquisition of Liberty Energy (California)		—		—		—		—			—			—			34,210			34,210
Amounts received in connection with Highground transaction		1,073		—		—		—			—			—			—			1,073

Balance, December 31, 2011	$	975,263	$	—	$	—	$	1,525		$	(366,080	)	$	(96,510	)	$	38,497		$	552,695

See accompanying notes to interim consolidated financial statements

Algonquin Power & Utilities Corp.

Consolidated Statements of Cash Flows


(thousands of Canadian dollars)
	2012			2011
Cash provided by (used in):

Operating Activities:
Net earnings from continuing operations	$	23,103		$	28,054
Adjustments and items not affecting cash:
Depreciation of property, plant and equipment		50,382			37,988
Amortization of intangible assets		4,151			6,433
Other amortization		2,175			2,192
Gain on sale of assets		—			(357	)
Deferred taxes		(14,304	)		(22,847	)
Unrealized (gain)/loss on derivative financial instruments		(3,127	)		2,324
Share-based compensation		1,956			769
Pension and post retirement expense		2,852			—
Write down of long lived assets		—			15,166
Unrealized foreign exchange loss		57			—
Changes in non-cash operating items (note 22)		(3,884	)		(1,542	)
Cash provided/(used) in discontinued operations (note 18)		(375	)		1,515

		62,986			69,695

Financing Activities:
Cash dividends on common shares		(36,917	)		(28,582	)
Cash dividends on preferred shares		(769	)		—
Cash distributions to non-controlling interests		(2,640	)		(523	)
Issuance of common shares		143,041			118,846
Proceeds from subscription receipts		61,160			—
Issuance of preferred shares		115,300			—
Deferred financing costs		(5,435	)		(3,642	)
Increase in long-term liabilities		505,542			204,759
Decrease in long-term liabilities		(75,432	)		(134,932	)
Increase in advances in aid of construction		1,051			6,288
Decrease in other long-term liabilities		(860	)		(297	)

		704,041			161,917

Investing Activities:
Decrease/(increase) in restricted cash		805			(1,036	)
Increase in short-term investments		—			(833	)
Increase in other assets		(2,481	)		(2,438	)
Distributions received in excess of equity income		343			3,839
Receipt of principal on notes receivable		1,894			1,172
Decrease in non-controlling interest		—			1,351
Proceeds from liquidation of Highground assets		—			1,073
Increase in long-term investments and notes receivable		—			(6,900	)
Proceeds from sale of property, plant and equipment		—			1,583
Proceeds from sale of subsidiaries		204			—
Additions to property, plant and equipment		(75,692	)		(60,745	)
Additions to intangibles (note 3(f))		(2,237	)		—
Acquisitions of operating entities (note 3(a),(b), and (d))		(669,905	)		(100,058	)
Acquisition of noncontrolling interest in Calpeco (note 3(e))		(38,756	)		—

		(785,825	)		(162,992	)

Effect of exchange rate differences on cash		(967	)		(482	)

Increase/(decrease) in cash and cash equivalents from continuing operations		(19,765	)		68,138

Cash and cash equivalents, beginning of the period		72,887			4,749

Cash and cash equivalents, end of the period	$	53,122		$	72,887


Supplemental disclosure of cash flow information:
Cash paid during the period for interest expense	$	28,635		$	28,143
Cash paid during the period for income taxes	$	252		$	195
Non-cash transactions
Property, plant and equipment acquisitions in accruals	$	10,495		$	8,556

See accompanying notes to consolidated financial statements

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2012 and 2011

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

Algonquin Power & Utilities Corp. (“APUC” or the “Company”) is an incorporated entity under the Canada Business Corporations Act. APUC’s principal activity is the ownership of power generation facilities and water, gas and electric utilities, through investments in securities of subsidiaries including corporations, limited partnerships and trusts which carry on these businesses.

APUC’s power generation business unit conducts business under the name Algonquin Power Co. (“APCo”). APCo owns or has interests in renewable energy facilities and thermal energy facilities. APUC’s Utility Services business unit conducts business under the name of Liberty Utilities Co. (“Liberty Utilities”). Liberty Utilities operates a portfolio of utilities in the United States of America providing electric, natural gas, water distribution or wastewater services.

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. Intercompany transactions and balances have been eliminated.

(c)

Accounting for rate regulated operations:

The regulated utility operating companies owned by Liberty Utilities 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 ASC Topic 980 Regulated Operations (“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 making process. Included in Note 7, Regulatory Assets & Liabilities 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 income for any remaining regulatory assets (liabilities). The impact could be material to the Company’s reported financial condition and results of operations.

The electric 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.

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2012 and 2011

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

1.	Significant accounting policies (continued)

(e)

Restricted cash:

Restricted cash represent 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 in these consolidated financial statements. APUC cannot access restricted cash without the prior authorization of parties not related to APUC.

(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)

Gas in storage

Gas in storage is reflected at weighted average cost or first-in-first-out as required by the 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).

(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.

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2012 and 2011

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

1.	Significant accounting policies (continued)

(i)

Property, plant and equipment (continued):

AFUDC represents the cost of borrowed funds (allowance for borrowed funds used during construction) and a return on other funds (allowance for equity funds used during construction). 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. The interest capitalized that relates to debt reduces interest expense on the Consolidated Statement of Operations. The AFUDC capitalized that relates to equity funds is recorded as interest, dividend and other income on the Consolidated Statement of Operations.


	2012		2011
Interest capitalized on non-regulated property	$	1,036	$	87
AFUDC capitalized on regulated property:
Allowance for borrowed funds		628		155
Allowance for equity funds		1,108		236

Total	$	2,772	$	478

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

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 range of estimated useful lives and the weighted average useful lives are summarized below:

Range of useful lives

Weighted average
useful lives

2012

2011

2012

2011

Generation

Renewable

3 – 60

Thermal

3 – 40

Distribution

Gas

5 – 80

N/A

Electrical

8 – 75

15 – 75

Water & wastewater

5 – 50

Equipment

5 – 50

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2012 and 2011

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

1.	Significant accounting policies (continued)

(i)

Property, plant and equipment (continued):

Contributions in aid of construction represent amounts contributed by customers and governments and developers for 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.

In accordance with regulator-approved accounting policies, when depreciable property, plant and equipment of Liberty Utilities 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 operation 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)

Intangibles:

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

The Company annually assesses qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit 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, 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, 2012 and 2011

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

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 analysis to assess whether its operations and investments represent variable interest entities (“VIEs”). To identify potential VIEs, management reviews contracts under leases, long-term purchase power agreements, tolling contracts 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 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.

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 100% of after tax cash flows of the facility up to the end of 2013, 65% from 2014 to 2027 and 58% 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. APUC has determined that the facility is a VIE since the Company is the primary beneficiary and therefore 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 $41,260 (2011 - $46,160) and to $37,143 (2011 - $38,136), respectively. The financial performance of Long Sault reflected on the statement of operations includes non-regulated energy sales of $8,747 (2011 - $9,804), operating expenses and amortization of $2,728 (2011 - $3,001) and interest expense of $3,929 (2011 - $3,984).

(n)

Long-term investments and notes receivable:

Investments in which APUC has significant influence but not control are accounted using the equity method. APUC records its share in the income or loss of its investees in interest, dividend and other income in the Consolidated Statement of Operations.

Notes receivable are financial assets with fixed or determined payments that are not quoted in an active market. Notes receivable that exceed one year and bear interest at a market rate based on the customer’s credit quality are initially recorded at cost, which is generally face value. Subsequent to acquisition, they 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.

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.

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2012 and 2011

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

1.	Significant accounting policies (continued)

(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 in other long-term liabilities. 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 2012, $3,207 (2011 - $1,107) 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 Liberty Utilities’ 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 credit worthy.

(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 other post employment benefit plans on the Consolidated Balance Sheets. The Company’s expense and liabilities are determined by actuarial valuations, using assumptions that are evaluated annually at 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 is recorded as actuarial gains and losses in accumulated other comprehensive income 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 Statement of Operations. The portion of pension and OPEB costs capitalized as cost of construction of plant and equipment is insignificant.

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2012 and 2011

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

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)

Stock 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 stock-based compensation as a cost in the 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)

Noncontrolling interests:

Noncontrolling interest represents the portion of equity ownership in subsidiaries that is not attributable to the equity holders of the parent Company. Noncontrolling interests are initially recorded at fair value and subsequently the amount is adjusted for the proportionate share of earnings and other comprehensive income attributable to the non-controlling interests and any dividends or distributions paid to the noncontrolling interests.

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

Certain of the Company’s U.S. based wind businesses (see note 3(d)) are organized as limited liability corporations and partnerships and have noncontrolling Class A membership equity investors which are entitled to allocations of earnings, tax attributes and cash flows in accordance with contractual agreements. The share of earnings attributable to the noncontrolling interest holders in these subsidiaries is calculated using the Hypothetical Liquidation at Book Value (“HLBV”) method of accounting. HLBV uses a balance sheet approach, which measures the allocation of income or loss of the Class A’s membership 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.

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2012 and 2011

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

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 sales and revenues 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.

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 waste water 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.

Revenue from waste disposal is recognized on actual tonnage of waste delivered to the plant at prices specified in the contract. Certain contracts include price reductions if specified thresholds are exceeded. Revenue for these contracts is recognized based on actual tonnage at the expected price for the contract year.

Interest from long-term investments is recorded as earned.

(v)

Foreign currency translation:

The Company’s reporting currency is the Canadian dollar.

The Company’s US 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 while revenues and expenses are converted 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 other comprehensive income (“OCI”) and are accumulated in a component of equity on the Consolidated Balance Sheet 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, 2012 and 2011

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

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 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.

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 follows ASC 740-10 and 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:

APUC has classified its cash and cash equivalents and restricted cash as held-for-trading, which are measured at fair value. Accounts receivable and notes receivable are measured at amortized cost and there is no liquid market for these investments. Long-term liabilities, convertible debentures, 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 for items classified as held-for-trading are expensed immediately. Transaction costs that are directly attributable to the issuance of financial liabilities, costs of arranging the Company’s credit facility 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 revolving credit facilities are amortized on a straight-line basis over the term of the 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 Sheet at their respective fair values. During 2011, none of the derivatives were designated in hedging relationships for accounting purposes and, as a result, the changes in the fair value were immediately recognized in the Consolidated Statements of Operations. In 2012, the Company commenced applying hedge accounting to financial instruments used to manage its foreign currency risk exposure and price risk exposure associated with sales of generated electricity.

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2012 and 2011

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

1.	Significant accounting policies (continued)

(x)

Financial instruments and derivatives (continued)

For derivatives designated in a cash flow hedge relationship, the effective portion of the change in fair value is recognized as other comprehensive income. The ineffective portion is immediately recognized in earnings. The amount recognized in accumulated other comprehensive income is removed and included in earnings in the same period as the hedged cash flows affect earnings under the same line item in the statement of income 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 accumulated other comprehensive income is transferred to the income statement in the same period that the hedged item affects profit or loss. If the forecast transaction is no longer expected to occur, then the balance in accumulated other comprehensive income is recognized immediately in earnings.

For derivative or financial instruments designated as a hedge of the foreign currency exposure of a net investment in foreign operations, foreign currency transaction gain or loss that are designated as, and are effective as, an economic hedge of the net investment in a foreign operation are reported in the same manner as the translation adjustment (in other comprehensive income) related to the net investment. To the extent that the hedge is ineffective, such differences are recognized in earnings.

Liberty Energy (California) (“Calpeco”) and Granite State Electric Company (“Granite State”) 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 on-going 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 principle 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.

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2012 and 2011

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

1.	Significant accounting policies (continued)

(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 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 and intangible assets, the annual impairment testing of reporting units containing goodwill, the recoverability of notes receivable and long-term investments, the recoverability of deferred tax assets, assessments of unbilled revenue, pension and OPEB obligations, contingencies related to environmental matters, and the fair value of financial instruments, derivatives and share-based compensation. 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, 2012 and 2011

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

2.	Recently issued accounting pronouncements

(a)

Recently adopted accounting pronouncements

In May 2011, the FASB issued ASU No. 2011-04 “Fair Value Measurement (Topic 820)”. This ASU amends the accounting and disclosure requirements for fair value measurements. The new guidance expands the disclosures about fair value measurements categorized within Level 3 of the fair value hierarchy and requires categorization by level of the fair value hierarchy for items that are not measured at fair value in the statement of financial position but for which the fair value is required to be disclosed. The adoption of this guidance in 2012 did not have a material impact on the Company’s consolidated financial statements.

(b)

Recent accounting guidance not yet adopted

The FASB issued ASU 2011-11, Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities and ASU 2013-01 Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities. These newly issued accounting standards require an entity to disclose both gross and net information about instruments and transactions eligible for offset in the statement of financial position as well as instruments and transactions executed under a master netting or similar arrangement and was issued to enable users of financial statements to understand the effects or potential effects of those arrangements on an entity’s financial position. These ASU are required to be applied retrospectively and are effective for fiscal years, and interim periods beginning on or after January 1, 2013. As these accounting standards only require enhanced disclosure, the adoption of these standards is not expected to have an impact the Company’s financial position or results of operations.

The FASB issued ASU 2013-02, Comprehensive Income (Topic 220). This newly issued accounting standard requires an entity to provide information about the amounts reclassified out of accumulated other comprehensive income by component. In addition, an entity is required to present, either on the face of the statement where net income is presented or in the notes, significant amounts reclassified out of accumulated other comprehensive income by the respective line items of net income but only if the amount reclassified is required under U.S. GAAP to be reclassified to net income in its entirety in the same reporting period. For other amounts that are not required under U.S. GAAP to be reclassified in their entirety to net income, an entity is required to cross-reference to other disclosures required under U.S. GAAP that provide additional detail about those amounts. This ASU is required to be applied prospectively for fiscal years, and interim periods beginning after December 15, 2012. As this accounting standard only requires enhanced disclosure, the adoption of this standard is not expected to have an impact the Company’s financial position or results of operations.

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2012 and 2011

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

3.	Business acquisitions and development projects

(a)

Acquisition of New Hampshire electric and gas utilities

On July 3, 2012, Liberty Utilities acquired 100% of the common shares of Granite State Electric Company, a regulated electric utility, and EnergyNorth Natural Gas Inc. (“EnergyNorth”) a regulated natural gas utility for total cash consideration of $299,501 (U.S. $295,805) subject to final closing adjustments.

The following table summarizes the preliminary determination of the fair value of the assets acquired and liabilities assumed at the acquisition date:


	Granite State			EnergyNorth			Total
Cash	$	395		$	—		$	395
Restricted cash		3,314			—			3,314
Working capital		1,778			25,255			27,033
Property, plant and equipment		86,935			256,305			343,240
Regulatory assets		32,068			87,203			119,271
Deferred financing		31			—			31
Other assets		172			83			255
Goodwill		—			27,580			27,580
Customer deposits		(661	)		(962	)		(1,623	)
Long-term debt		(15,187	)		—			(15,187	)
Other long-term liabilities		(1,193	)		(4,493	)		(5,686	)
Advances in aid of construction		—			(86	)		(86	)
Derivative liabilities		—			(2,601	)		(2,601	)
Regulatory liabilities		(5,494	)		(27,572	)		(33,066	)
Pension and OPEB		(19,108	)		(29,197	)		(48,305	)
Environmental obligation		—			(54,431	)		(54,431	)
Deferred income tax liabilities, net		—			(60,633	)		(60,633	)

	$	83,050		$	216,451		$	299,501
Less: Cash acquired		(395	)		—			(395	)

Total net assets acquired	$	82,655		$	216,451		$	299,106

The determination of the fair value of assets and liabilities acquired has been based upon management’s preliminary estimates and certain assumptions with respect to the fair values of the assets acquired and liabilities assumed. The Company has not completed the fair value measurements. In addition, the purchase agreements provides for a final purchase price adjustment based on final agreed working capital and rate base balances at the acquisition date. The Company will continue to review information and perform further analysis prior to finalizing the fair value of the consideration paid and the fair value of the assets acquired and liabilities assumed. The actual fair values of the assets acquired and liabilities assumed may differ from the amounts above.

Goodwill represents the excess of the fair value of the consideration paid over the fair value of net identifiable assets acquired. The contributing factors to the amount recorded as goodwill include expected future cash flows, potential operational synergies, the utilization of technology, and cost savings opportunities in the delivery of certain shared administrative and other services. The goodwill related to EnergyNorth and Granite State has been allocated to the Liberty Utilities (East) segment.

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2012 and 2011

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

3.	Business acquisitions and development projects (continued)

(a)

Acquisition of New Hampshire electric and gas utilities (continued)

Property, plant & equipment are amortized in accordance with regulatory requirements which are generally over the estimated useful lives of the assets using the straight line method. The weighted average life of the acquired assets of EnergyNorth and Granite State are 40 years and 28 years respectively.

All transaction costs related to the acquisition have been expensed through the Consolidated Statement of Operations.

Granite State and EnergyNorth contributed revenue of $86,993 and a net loss of $354 to the Company’s results in 2012. Pro forma financial information is disclosed in note 3(c).

(b)

Acquisition of Midwest Gas Utilities

On August 1, 2012, Liberty Utilities acquired certain regulated natural gas distribution utility assets (the “Midwest Gas Utilities”) located in Missouri, Iowa, and Illinois. The total purchase price for the Midwest Utilities was approximately $128,890 (U.S. $128,223), subject to final closing adjustments.

The following table summarizes the preliminary determination of the fair value of the assets acquired and liabilities assumed at the acquisition date:


Working capital and restricted cash	$	7,130
Property, plant and equipment		123,631
Regulatory assets		146
Deferred income tax assets, net		9,215
Goodwill		25,162
Current portion of long-term liabilities		(1,841	)
Current portion of derivative liabilities		(547	)
Advances in aid of construction		(276	)
Regulatory liabilities		(28,581	)
Pension and OPEB		(5,149	)

Total net assets acquired	$	128,890

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2012 and 2011

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

3.	Business acquisitions and development projects (continued)

(b)

Acquisition of Midwest Gas Utilities (continued)

Goodwill represents the excess of the fair value of the consideration paid over the fair value of net assets acquired. The contributing factors to the amount recorded as goodwill include expected future cash flows, potential operational synergies, the utilization of technology, and cost savings opportunities in the delivery of certain shared administrative and other services. The goodwill related to Midwest Gas Utilities has been allocated to the Liberty Utilities (Central) segment.

Property, plant & equipment are amortized in accordance with regulatory requirements over the estimated useful life of the asset using the straight line method. The weighted average life is 30 years.

All transaction costs related to the acquisition have been expensed through the Consolidated Statement of Operations.

Midwest Gas Utilities contributed revenue of $25,936 and net earnings of $1,229 to the Company’s results in 2012. Pro forma financial information is disclosed in note 3 (c).

(c)

Pro forma financial information

The supplemental pro forma financial information below was prepared using the acquisition method of accounting and is based on the historical financial information of APUC, Granite State, EnergyNorth and the Midwest Gas Utilities, reflecting results of operations for the years ended December 31, 2012 and 2011 on a comparative basis as though the aforementioned companies were combined as of the beginning of fiscal year 2011. The estimated acquirees’ pre-acquisition results have been added to APUC’s historical results, and the totals have been adjusted for the pro forma effects of acquisition-related costs, interest expense related to the financing of the business combinations, and related income taxes.


Pro forma	2012		2011
Total revenue	$	521,538	$	574,618
Net earnings attributable to APUC		22,584		33,328
Basic net earnings per share		0.14		0.23
Diluted net earnings per share		0.14		0.23

The above unaudited pro forma financial information is presented for informational purposes only and does not purport to represent what the results would have been had the acquisition closed on the date assumed, nor is it necessarily indicative of the results that may be expected in future periods.

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2012 and 2011

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

3.	Business acquisitions and development projects (continued)

(d)

Acquisition of U.S. wind farms

On July 1, 2012, APCo acquired a 51% controlling interest in the Pennsylvania based 50MW Sandy Ridge Wind Project (“Sandy Ridge”) for approximately $30,121 (U.S. $29,749). In October, APCo acquired an additional 7.75% interest for U.S. $4,521.

On December 10, 2012, APCo acquired a 58.75% controlling interest in both the 150 MW Senate Wind Project (“Senate”) in Texas and the 200 MW Minonk Wind Project (“Minonk”) in Illinois for approximately $87,646 (U.S. $88,801) and $143,652 (U.S. $145,544), respectively. On the same date, APCo acquired an additional 1.25% interest in all three projects bringing the total interest to 60% for additional consideration of U.S. $ 3,100.

The three wind projects are being acquired through Wind Portfolio Holdings LLC., a newly formed partnership whose members include Class B members consisting of APCo, through one of its subsidiaries, (holding a 60% controlling Class B interest) and Gamesa Corporación Tecnológica, S.A. (“Gamesa”), the original developer of the projects, (holding a 40% interest in Class B membership units) and certain Class A equity investors. In exchange for the cash contributed, the Class A members will receive a portion of the economic attributes of the facility, including Production Tax Credits, allocated taxable income or loss and cash distributions, until the date they achieve the targeted internal rate of return (the ‘Flip Date’) on their investment. Pursuant to the allocation rules specified in the LLC operating agreement, all operating cash flow is allocated to the Class B members until the earlier of a fixed date, or when the Class B members recover the amount of invested Class B capital. This is expected to occur between five to seven years from the initial closing date. Thereafter, 65% of operating cash flow is allocated to the Class A members until the Flip Date, which is expected to occur between eight and ten years from the initial closing date. After the initial year until the Flip Date, substantially all of the taxable income and benefits generated by the partnerships are allocated to the Class A members, with any remaining benefits allocated to the Class B members.

The following table summarizes the assets acquired and liabilities assumed at the acquisition dates. The equity interests show APCo’s total interest of 60% to reflect the nature of the transaction:


	Sandy Ridge			Senate			Minonk			Total
Cash	$	1,365		$	5,336		$	16,528		$	23,229
Property, plant and equipment		87,278			287,111			380,744			755,133
Derivative asset (liability)		1,655			(8,639	)		3,736			(3,248	)
Working capital		(1,365	)		(5,336	)		(16,528	)		(23,229	)
Asset retirement obligation		(1,662	)		(1,697	)		(2,262	)		(5,621	)

Total net assets acquired	$	87,271		$	276,775		$	382,218		$	746,264


Equity interests:
APCo Class B membership interest	$	35,169		$	88,748		$	145,151		$	269,068
Additional paid in capital		192			919			1,250			2,361
Noncontrolling interests:
Class A members		28,211			127,590			137,703			293,504
Class B members		23,699			59,518			98,114			181,331

	$	87,271		$	276,775		$	382,218		$	746,264

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2012 and 2011

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

3.	Business acquisitions and development projects (continued)

(d)

Acquisition of U.S. wind farms (continued)

Property, plant & equipment are amortized on a straight line basis over the lives of the assets, which have a weighted average life of 32 years.

All transaction costs related to the acquisition have been expensed through the Consolidated Statement of Operations.

The contribution of the U.S. wind farms to the Company’s results in 2012 was as follows:


	Revenue		Net earnings/(Loss)
Sandy Ridge	$	2,132	$	(353	)
Senate		1,179		50
Minonk		785		(146	)

	$	4,096	$	(449	)

The disclosure of pro forma revenue and net earnings is impracticable as there is no historical financial information since APCo acquired the wind farms shortly after commencement of commercial operations.

(e)

Acquisition of noncontrolling interest in Calpeco

On December 21, 2012, APUC acquired the 49.999% interest in Calpeco from Emera Inc.(“Emera”) for $38,756 which was funded by the proceeds of common share subscription receipts (note 14(a)(iii)). The impact on the Company’s Consolidated Balance Sheet was as follows:


Elimination of noncontrolling interest (net of intercompany balance of $1,297 with Emera)	$	33,726
Noncontrolling interest portion of currency translation adjustment transferred to AOCI		1,397
Accumulated deficit		3,633

Exercise of subscription receipts	$	38,756

(f)

Acquisition of solar energy project

On January 4, 2012, APCo acquired rights to develop a 10 MWac solar project located near Cornwall, Ontario which has been granted a Feed-in-Tariff contract by the Ontario Power Authority for a 20 year term at a rate of $443/MWh. The consideration for the development rights is $4,500 plus additional contingent consideration of $3,500 based on achieving certain construction milestones. As at December 31, 2012, the Company has paid a total of $2,000 based on achieved milestones. The transaction has been recorded as a purchase of intangible assets.

(g)

Acquisition of Shady Oaks wind power facility

Subsequent to year-end, effective January 1, 2013, APCo acquired the 109.5 MW Sandy Oaks wind powered generating facility by assuming the existing long-term debt of approximately U.S. $150 million for no additional cash. 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. The energy and basis related price adjustment will be based on the project’s experience from January 1, 2013 to June 30, 2014.

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2012 and 2011

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

3.	Business acquisitions and development projects (continued)

(g)

Acquisition of Shady Oaks wind power facility (continued)

The current portion of the long-term debt of U.S. $25,000 and U.S. $3,000 are payable on June 30 and November 15, 2013, respectively. The semi-annual principal repayment schedule for the following 11 years ranges from $3,000 to $6,000 with a final repayment of U.S. $20,000 in 2025. This debt may be repaid in whole or in part at anytime without penalty and bears interest at Libor plus 280 basis points.

All costs related to the acquisition have been expensed through the Consolidated Statement of Operations.

Based on the timing of the completion of this acquisition in relation to the date of issuance of the financial statements, the initial allocation of the consideration paid has not been completed.

(h)

Agreement to acquire Regulated Gas Utility in Georgia

On August 8, 2012, Liberty Utilities entered into an agreement with Atmos Energy Corporation (“Atmos”) to acquire certain regulated natural gas distribution utility assets (the “Georgia Utility”) located in the State of Georgia. Total purchase price for the Georgia Utility is approximately U.S. $140,660, subject to certain working capital and other closing adjustments. Regulatory approval was obtained in February 2013 and the acquisition is expected to close on or about April 1, 2013.

(i)

Acquisition of Arkansas Regulated Water Utility

Subsequent to year-end, on February 1, 2013, Liberty Utilities acquired United Water Arkansas Inc. a regulated water distribution utility (the “Arkansas Utility”) located in Pine Bluff, Arkansas. Total purchase price for the Arkansas Utility is approximately U.S. $27,600, subject to certain working capital and other closing adjustments.

All costs related to the acquisition have been expensed through the Consolidated Statement of Operations.

Based on the timing of the completion of this acquisition in relation to the date of issuance of the financial statements, the initial allocation of the consideration paid has not been completed.

(j)

Agreement to acquire New England Gas Company

Subsequent to year-end, on February 11, 2013, Liberty Utilities entered into an agreement with The Laclede Group, Inc. to assume the rights to purchase the assets of New England Gas Company (“New England Gas”) located in the State of Massachusetts. Total purchase price for the New England Gas is approximately U.S. $74,000, 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 second half of 2013.

4.	Accounts receivable

Accounts receivable as of December 31, 2012, includes unbilled revenue of $22,658 (December 31, 2011 - $11,304) in the regulated utilities. The unbilled revenue is an estimate of the amount of utility revenue since the date the meters were last read that has not yet been billed to customers.

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2012 and 2011

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

5.	Property, plant and equipment

Property, plant and equipment consist of the following:


2012
	Cost		Accumulated depreciation		Net book value
Generation
Renewable		1,244,912	$	119,809	$	1,125,103
Thermal		208,183		78,336		129,847
Distribution
Water & wastewater		240,376		52,162		188,214
Electricity		259,461		7,765		251,696
Gas		352,491		5,940		346,551
Land		12,006		—		12,006
Equipment		71,954		26,697		45,257
Construction in progress		64,041		—		64,041

	$	2,453,424	$	290,709	$	2,162,715


2011
	Cost		Accumulated depreciation		Net book value
Generation
Renewable	$	488,920	$	117,740	$	371,180
Thermal		194,080		78,776		115,304
Distribution
Water & wastewater		239,190		48,716		190,474
Electricity		154,154		2,636		151,518
Land		11,981		—		11,981
Equipment		47,599		21,865		25,734
Construction in progress		53,918		—		53,918

	$	1,189,842	$	269,733	$	920,109

Renewable generation assets include cost of $88,198 (2011 - $94,606) and accumulated depreciation of $29,584 (2011 - $30,264) related to facilities under capital lease or owned by consolidated variable interest entities. Depreciation expense of facilities under capital lease was $2,244 (2011 - $2,302).

Equipment includes cost of $4,227 (2011 - $4,227) and accumulated depreciation of $2,348 (2011 - $2,079) related to equipment under capital lease. Depreciation expense of equipment under capital lease was $269 (2011 - $282).

Contributions received in aid of construction of $6,341 (2011 - $3,968) 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, 2012 and 2011

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

5.	Property, plant and equipment (continued)

In 2012, APCo wrote down its investment in a small hydro facility and recognized an impairment charge on property, plant and equipment of $253 (2011 - $1,370) representing the difference between the carrying value of the assets and their estimated fair value. The fair value of the facilities was estimated based on prior transactions involving sales of comparable facilities and management’s best estimates.

In December 2011, Liberty Utilities wrote down $1,058 from facilities` assets based on regulatory decisions in 2011 that these costs are not capitalizable for rate-base purposes.

6.	Intangible assets

Intangible assets consist of the following:


2012
	Cost		Accumulated amortization		Net book value
Power sales contracts	$	60,435	$	24,881	$	35,554
Customer relationships		26,674		5,447		21,227

	$	87,109	$	30,328	$	56,781


2011
	Cost		Accumulated amortization		Net book value
Power sales contracts	$	52,073	$	19,123	$	32,950
Customer relationships		27,206		4,887		22,319

	$	79,279	$	24,010	$	55,269

The Region of Peel elected not to extend the existing waste processing contract with the Company. As a result, the remaining intangible assets associated with the existing waste management and energy contracts of the facility were written off in 2011 and the Company recognized a charge on intangible assets of $13,430.

Estimated amortization expense for intangibles for the next four years is $4,200 each year and $2,450 in year five.

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2012 and 2011

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

7.	Regulatory matters

The Company’s regulated utility operating companies owned by Liberty Utilities are subject to regulation by the respective public utility commissions of the states in which they operate, and the FERC in some instances. The respective state public utility commissions have jurisdiction with respect to rate, service, accounting procedures, issuance of securities, acquisitions and other matters. These utilities operate under cost-of-service regulation as administered by these state authorities.

The utilities periodically file rate cases with their regulators. Rate cases seek to ensure that a particular facility has the opportunity to recover its operating costs and earn a fair and reasonable return on its capital investment as allowed by the regulatory authority under which the facility operates. Regulated utilities use a test year in the establishment of rates for the utility and pursuant to this method the determination of the rate of return on approved rate base and deemed capital structure, together with all reasonable and prudent costs, establishes the revenue requirement upon which each utility’s customer rates are determined.

Liberty Utilities monitors current and anticipated operating costs, capital investment and the rates of return in respect of each of its facility investments to determine the appropriate timing of a rate case filing in order to ensure it fully earns a rate of return on its investments.

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2012 and 2011

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

7.	Regulatory matters (continued)

Regulatory assets and liabilities consist of the following:


	2012			2011
Regulatory assets:
Environmental costs (a)	$	59,789		$	—
Pension and post-retirement benefits (b)		47,838			—
Storm costs deferral (c)		6,726			—
Deferred energy costs (d)		7,962			—
Derivative assets (e)		1,731			—
Rate case costs (f)		4,480			2,161
Alternative revenue program (g)		272			2,789
Asset retirement obligation (h)		1,095			—
Other		4,499			79

Total regulatory assets	$	134,392		$	5,029
Less current regulatory assets		(10,644	)		(2,458	)

Non-current regulatory assets	$	123,748		$	2,571

Regulatory liabilities
Cost of removal (i)	$	58,852		$	14,945
Rate-base offset (j)		15,541			—
Energy costs adjustment (d)		11,706			6,708
Pension and post-retirement benefits (b)		1,127			—
Derivative liabilities (e)		616			—
Other		273			—

Total regulatory liabilities	$	88,115		$	21,653
Less current regulatory liabilities		(6,065	)		(2,469	)

Non-current regulatory liabilities	$	82,050		$	19,184

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2012 and 2011

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

7.	Regulatory matters (continued)

(a)

Environmental remediation costs recovery: EnergyNorth is responsible for the cleanup of certain former gas manufacturing facilities. Actual expenditures are recovered through rates over a period of 7 years (see note 21 (a) (ii)).

(b)

Pension and post-retirement benefits: As part of a business acquisition, a regulatory asset or liability is set up for the amounts of pension and post-retirement benefits that have not yet been recognized in net periodic cost and were presented as accumulated comprehensive income prior to the acquisition. The portion currently recovered through rates is amortized over the future services years of the employees. The portion related to the current acquisitions which amounts to U.S. $43,484 was authorized by the Regulator as a regulatory asset and recovery is expected to start following the next rate case.

(c)

Storm costs: Granite State incurred repair costs resulting from certain storms, which are expected to be recovered through rates.

(d)

Deferred energy cost: The revenue of the electric and natural gas utilities include 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 statement of operations but rather is deferred and recorded as a regulatory asset or liability on the balance sheet. These differences are reflected in adjustments to rates and recorded as an adjustment to cost of natural gas or electricity in future time periods, subject to regulatory review.

(e)

Derivatives: Derivatives are utilized to manage the price risk associated with natural gas purchasing activities. The gains and losses associated with these derivatives are recoverable through its deferred energy cost, as noted above, (note 24(b)(i)).

(f)

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.

(g)

Alternative revenue program: In 2011, the regulator of one of Liberty Utilities’ utilities ordered to phase-in the rate increases it had granted over a 12 month period.

(h)

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

(i)

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.

(j)

Rate-base offset: The Regulator for the Midwest Gas Utilities 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.

The Company records carrying charges on the regulatory balances related to energy costs, storm costs and rate adjustments. As recovery of regulatory assets is subject to regulatory approval, if there are any changes in regulatory positions that indicate recovery is not probable, the related cost would be charged to income in the period of such determination.

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2012 and 2011

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

8.	Long-term investments and notes receivable

Long-term investments and notes receivable consist of the following:


	2012			2011
Red Lily Senior loan, interest at 6.31% (a)	$	11,588		$	13,000
Red Lily Subordinated loan, interest at 12.5% (a)		6,565			6,565
32.4% of Class B non-voting shares of Kirkland Lake Power Corp.		4,926			4,926
25% of Class B non-voting shares of Cochrane Power Corporation		4,669			5,382
45% interest in the Algonquin Power (Rattle Brook) Partnership		3,884			3,784
Chapais Énergie, Société en Commandite interest at 10.789% and 4.91%, respectively		2,448			2,913
Silverleaf resorts loan, interest at 15.48% maturing July 2020		2,010			2,056
50% interest in the Valley Power Partnership		1,767			1,676
Other		326			—

		38,183			40,302
Less: current portion		(537	)		(482	)

Total long term investments and notes receivable	$	37,646		$	39,820

The above notes are secured by the underlying assets of the respective facilities. There is no impairment provision in regards to the notes receivable as at December 31, 2012 and 2011.

(a)

Red Lily I

The Red Lily I Partnership (“Partnership”) is owned by an independent investor. The Company provides operation and supervision services to the Red Lily I project, a 26.4 megawatt wind energy facility located in south-eastern 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 from the Partnership. In 2011, APUC advanced $13,000 under a senior debt facility to the Partnership and received a pre-payment of $1,412 in 2012. Another third party lender has also advanced $31,000 of senior debt to the Partnership. The Company’s senior loan to the Partnership earns interest at the rate of 6.31% and will mature in 2016. 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%, 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 APUC’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 at December 31, 2012 and 2011 was determined to be negligible.

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2012 and 2011

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

9.	Long-term liabilities

Long term liabilities consist of the following:


	2012		2011
APCo

Revolving $200,000 credit facility, revolving line of credit 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 1.75%, maturing November 16, 2015.	$	27,074	$	—

Senior Unsecured Notes: $150,000 senior unsecured notes, interest rate of 4.82% maturing February 15, 2021. The notes are interest only, payable semi-annually in arrears.		149,910		—

Senior Unsecured Notes: $135,000 senior unsecured notes, interest rate of 5.5% maturing July 25, 2018. The notes are interest only, payable semi-annually in arrears.		134,807		134,778

Senior Debt Long Sault Rapids: Interest at rate of 10.2% repayable in blended monthly interest and principal installments of $402 and maturing December 31, 2027.		38,136		39,033

Sanger Bonds: U.S. $19,200 California Pollution Control Finance Authority Variable Rate Demand Resource Recovery Revenue Bonds Series 1990A, interest payable monthly, maturing September 15, 2020. The variable interest rate is determined by the remarketing agent. The effective interest rate for 2012 is 2.29% (2011 – 2.05%).		19,102		19,526

Senior Debt Chute Ford: Interest rate of 11.6% repayable in blended monthly interest and principal installments of $64 and maturing April 1, 2020.		3,763		4,072

Liberty Utilities

Revolving U.S. $100,000 credit facility, revolving line of credit interest rate is equal to bankers acceptance or LIBOR plus a variable rate as outlined in the credit facility agreement. The current rate is LIBOR plus 1.625%, maturing January 18, 2015.		27,360		—

Senior Unsecured Notes:

Liberty Utilities Co. Senior unsecured notes, U.S. $50,000, bearing an interest rate of 3.51%, maturing July 31, 2017; U.S. $115,000, bearing an interest rate of 4.49%, maturing August 1, 2022; and, U.S. $60,000, bearing an interest rate of 4.89%, maturing July 30, 2027. The notes are interest only, payable semi-annually.		223,852		—

California Pacific Electric Company, LLC: U.S. $45,000 senior unsecured notes, interest rate of 5.19%, maturing December 29, 2020 and U.S. $25,000, interest rate of 5.59%, maturing December 29, 2025. The notes are interest only, payable semi-annually.		69,643		71,190

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2012 and 2011

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

9.	Long-term liabilities (continued)


	2012			2011
Liberty Water Co: U.S. $50,000 senior unsecured notes, interest rate of 5.6% maturing December 22, 2020. The notes are interest only, payable semi-annually, until June 20, 2016 with semi-annual interest payments and an annual principal repayment of U.S. $5,000 thereafter.		49,745			50,850

Granite State: 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 are interest only, payable semi-annually.		14,924			—

Litchfield Park Service Company Bonds: 1999 and 2001 IDA Bonds. Interest rates of 5.95% and 6.75% repayable in blended semi-annual installments maturing October 1, 2023 and October 1, 2031. Principal payments of U.S. $285 (2011 – U.S. $270). The balance of these notes at December 31, 2012 was U.S. $3,390 and U.S. $7,030, respectively (2011 – U.S. $3,605 and U.S. $7,100).		11,269			11,868

Bella Vista Water Loans: Water Infrastructure Financing Authority of Arizona Interest rates of 6.26% and 6.10% repayable in monthly and quarterly installments (U.S. $15 and U.S. $4) maturing March 1, 2020 and December 1, 2017. The balance of these notes at December 31, 2012 was U.S. $1,167 and U.S. $80 respectively (2011 – U.S. $1,275 and U.S. $83)		1,241			1,399

	$	770,826		$	332,716
Less: current portion		(1,768	)		(1,624	)

	$	769,058		$	331,092

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 APUC, APCo or Liberty Utilities. The loans have certain financial covenants, which must be maintained on a quarterly basis. Non compliance with the covenants could restrict cash distributions/dividends to Liberty Utilities, APCo and APUC from the specific facilities.

APCo

On December 3, 2012, APCo issued $150,000 senior unsecured debentures bearing interest at 4.82% and with a maturity date of February 15, 2021. The debentures were sold at a price of $99.94 per $100.00 principal amount. Interest payments will be payable on February 15 and August 15 each year, commencing on February 15, 2013. APCo incurred deferred financing costs of $1,057, which are being amortized to interest expense over the term of the loan using the effective interest rate method. Concurrent with the offering, APCo entered into a cross currency swap, coterminous with the debentures, to economically convert the Canadian dollar denominated offering into U.S. dollars (note 24(b)(iii)).

In 2012, APCo increased the maximum availability under its senior credit facility from $120,000 to $200,000 to meet future working capital needs. In addition, the bank syndicate agreed to release its security previously held over certain APCo entities, such that the facility is now fully unsecured. The facility has a maturity date of November 16, 2015.

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2012 and 2011

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

9.	Long-term liabilities (continued)

APCo (continued)

On July 25, 2011 APCo completed a $135,000 private placement debt financing at a price of $998.28 per $1,000 principal amount of debenture. The notes are senior unsecured with a maturity date of July 25, 2018 and bear interest at 5.5%. The notes are interest only, payable semi-annually in arrears, commencing January 25, 2012. APCo incurred deferred financing costs of $1,685, which are being amortized to interest expense over the term of the loan using the effective interest rate method. The net proceeds of this financing were used to retire the project debt related to the St. Leon facility (Air Source Senior Debt Financing) and to reduce amounts outstanding on APCo’s senior secured revolving credit facility.

Liberty Utilities

Subsequent to year end, on March 14, 2013 Liberty Utilities entered into a variable rate unsecured U.S. $100,000 term facility with a U.S. Bank. Drawings under the facility are conditional upon closing of certain planned acquisitions by Liberty Utilities. The loan is non-revolving and matures on December 31, 2013.

Subsequent to year end, on March 14, 2013 Liberty Utilities issued U.S. $15,000 of senior unsecured notes through a private placement in connection with the acquisition of the Arkansas Utility (note 3 (h)). The notes bear interest at 4.14% and mature in 10 years.

In July 2012, Liberty Utilities issued U.S. $225,000 of senior unsecured notes through a private placement in three tranches: U.S. $50,000, bearing an interest rate of 3.51%, maturing July 31, 2017; U.S. $115,000, bearing an interest rate of 4.49%, maturing August 1, 2022; and, U.S. $60,000, bearing an interest rate of 4.89%, maturing July 30, 2027. The notes are interest only, payable semi-annually. Liberty Utilities incurred deferred financing costs of $2,663, which are being amortized to interest expense over the term of the loan using the effective interest rate method. Liberty Utilities used the proceeds of the private placement financing to fund a portion of the acquisition of the New Hampshire and Midwest Gas Utilities (notes 3(a) and (b)).

On July 3, 2012, in connection with the acquisition of Granite State, Liberty Utilities assumed senior unsecured long-term notes of 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.

On January 18, 2012, Liberty Utilities entered into an agreement for a senior unsecured revolving credit facility (the “Liberty Facility”) with a three year term. Effective July 3, 2013, the maximum credit available under the facility is U.S. $100,000.

In 2011, Calpeco issued U.S. $70,000 senior unsecured notes consisting of U.S. $45,000 bearing an interest rate of 5.19% maturing December 29, 2020 and U.S. $25,000 bearing an interest rate of 5.59% maturing December 29, 2025. The notes are interest only, payable semi-annually. Total financing costs of $ 1,048 incurred with respect to this placement have been recorded in deferred financing costs.

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2012 and 2011

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

APUC

On November 19, 2012, APUC entered into a $30 million senior unsecured revolving credit facility. The credit facility will be used for general corporate purposes and has a maturity date of November 19, 2015

As of December 31, 2012, the Company had accrued $4,482 in interest payable (2011 - $3,255). Interest paid on the long-term liabilities in 2012 was $20,671 (2011 - $18,089).

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


	2013		2014		2015		2016		2017		Thereafter		Total
APCo	$	1,339	$	1,483	$	28,721	$	1,829	$	2,032	$	337,388	$	372,792
Liberty Utilities		429		449		27,837		5,481		55,256		308,582		398,034

Total	$	1,768	$	1,932	$	56,558	$	7,310	$	57,288	$	645,970	$	770,826

10.

Convertible debentures


	Series 1A			Series 2A			Series 3			Total
Maturity date	2014 November 30			2016 November 30			2017 September 30
Interest rate		7.50	%		6.35	%		7.00	%
Conversion price per share	$	4.08		$	6.00		$	4.20

Carrying value at December 31, 2010	$	59,156		$	59,699		$	62,905		$	181,760
Conversion to common shares (Note14(a)(ii)), net of costs		(59,449	)		(10	)		(334	)		(59,793	)
Amortization and accretion		293			37			—			330

Carrying value at December 31, 2011	$	—		$	59,726		$	62,571		$	122,297
Conversion to common shares (note 14(a)(ii)), net of costs		—			(59,950	)		(61,611	)		(121,561	)
Amortization and accretion		—			224			—			224

Carrying amount at December 31, 2012	$	—		$	—		$	960		$	960

Face value at December 31, 2012	$	—		$	—		$	960		$	960

Subsequent to year-end, the remaining principal amount of $960 of Series 3 Debentures was redeemed for 150,816 shares of APUC (note 14(a)(ii)).

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2012 and 2011

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

11.

Pension and other post-retirement benefits

In conjunction with recent utilities acquisitions, the Company assumed defined benefit pension and OPEB plans for qualifying employees in the related acquired businesses. The electricity and gas utilities, other than Calpeco, each have noncontributory defined pension plans covering substantially all employees. Benefits are based on each employee’s years of service and compensation. Calpeco has a defined benefit cash balance pension plan covering substantially all its employees, under which employees are credited with a percentage of base pay plus a prescribed interest rate credit. The Company’s policy is to make pension contributions within the range determined by generally accepted actuarial principles. 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.

The Company acquired EnergyNorth, Granite State and the Midwest Utilities in the third quarter of 2012; therefore, they are not included in the December 31, 2011 comparative information. The determination of the fair value of pension and OPEB assets and liabilities acquired has been based upon management’s preliminary estimates and certain assumptions. Namely, plan assets acquired had not been transferred to the Company as at December 31, 2012. An estimate of the assets to be transferred adjusted for estimated return, contributions and benefits was used to estimate the funded status at the acquisition date and December 31, 2012. The Company will continue to review information and perform further analysis prior to finalizing the fair value of the pension and OPEB assets acquired and liabilities assumed. The actual fair values of the assets acquired and liabilities assumed may differ from the amounts recorded.

(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 at December 31:


	Pension benefits					OPEB
	2012			2011		2012			2011
Change in projected benefit obligation
Projected benefit obligation, at beginning of year	$	239		$	—	$	—		$	—
Assumed projected obligation from business combination		101,840			—		30,637			—
Service cost		1,288			180		803			—
Interest cost		1,906			—		606			—
Actuarial loss		2,736			52		857			—
Benefits paid		(1,507	)		—		(601	)		—
Foreign exchange		(2,211	)		7		(628	)		—

Projected benefit obligation, at end of year	$	104,291		$	239	$	31,674		$	—

Change in plan asset
Fair value of plan assets, at beginning of year		203			—		—			—
Acquired assets in business combination		68,045			—		10,786			—
Actual return on plan assets		1,223			—		—			—
Employer contributions		—			233		231			—
Benefits paid		(1,507	)		—		(601	)		—
(Gain)/Loss on foreign exchange		(1,440	)		6		(221	)		—

Fair value of plan assets, at end of year	$	66,524		$	239	$	10,195		$	—

Unfunded status	$	(37,767	)	$	—	$	(21,479	)	$	—

Amounts recognized in the Consolidated Balance Sheet consists of:
Current liabilities		—			—					—
Noncurrent liabilities		(37,767	)		—		(21,479	)		—

Net amount recognized	$	(37,767	)	$	—	$	(21,479	)	$	—

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2012 and 2011

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

11.

Pension and other post-retirement benefits (continued)

(b)

Net pension and OPEB obligation (continued)

The accumulated benefit obligation for the pension plan was $97,687 and $239 at December 31, 2012 and 2011, respectively.

The amounts recognized in accumulated other comprehensive loss were as follows:


	Accumulated other comprehensive income
	Pension			OPEB
Balance, January 1, 2011
Current year net actuarial loss	$	47		$	—
Foreign exchange		1			—

Balance at December 31, 2011	$	48		$	—

Current year net actuarial loss		3,303			857
Amortization of net actuarial loss		(2	)		(32	)
Foreign exchange		(16	)		(4	)

Balance at December 31, 2012	$	3,333		$	821

(c)

Assumptions

Weighted average assumptions used to determine net benefit cost for 2012 and 2011 were as follows:


	Pension benefits						OPEB
	2012			2011			2012			2011
Discount rate		3.89	%		4.75	%		3.97	%		N/A
Expected return on assets		5.50	%		6.00	%		4.66	%		N/A
Rate of compensation increase		3.31	%		4.00	%		N/A			N/A
Healthcare cost trend rate
Before Age 65								8.48	%		N/A
Age 65 and after								7.50	%		N/A
Assumed Ultimate Medical Inflation Rate								5.00	%		N/A
Year in which Ultimate Rate is reached								2017			N/A

Weighted average assumptions used to determine net benefit obligation for 2012 and 2011 were as follows:


	Pension benefits						OPEB
	2012			2011			2012			2011
Discount rate		3.62	%		4.00	%		3.75	%		N/A
Expected return on assets		5.50	%		6.00	%		4.66	%		N/A
Rate of compensation increase		3.09	%		4.00	%		N/A			N/A

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.

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2012 and 2011

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

11.

Pension and other post-retirement benefits (continued)

(c)

Assumptions (continued)

The effect of a one percent change in the assumed health care cost trend rate (HCCTR) for 2012 is as follows:


	2012
Effect of a 1 percentage point increase in the HCCTR on:
Year-end benefit obligation	$	4,153
Total service and interest cost		177
Effect of a 1 percentage point decrease in the HCCTR on:
Year-end benefit obligation	$	(3,356	)
Total service and interest cost		(142	)

(d)

Benefit costs

The following table lists the components of net benefit costs for the pension plans and OPEB recorded as part of administrative expenses in the Consolidated Statement of Operations. The employee benefit costs related to business acquired are recorded in the Consolidated Statement of Operations from the date of acquisition. The portion of employee benefit capitalized as cost of construction is insignificant.


	Pension benefits					OPEB
	2012			2011		2012		2011
Service cost	$	1,288		$	180	$	803	$	—
Interest cost		1,906			—		606		—
Expected return on plan assets		(1,785	)		—		—		—
Amortization of net actuarial loss		2			—		32		—

Net benefit cost	$	1,411		$	180	$	1,441	$	—

The net actuarial loss for the defined benefit pension plan that will be amortized from accumulated other comprehensive income into net periodic benefit cost over the next fiscal year are $11 and $37, respectively.

(e)

Plan assets

The Company’s investment strategy for its pension and post-retirement 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 total amount of plan assets acquired through business acquisitions in 2012 was determined but had not been transferred to the Company as at December 31, 2012. An estimate of the assets to be transferred adjusted for estimated return, contributions and benefits was used to estimate the funded status at December 31, 2012. Detailed investment allocation decisions will be finalized following the plan asset transfer that is expected to occur in the first quarter of 2013.

(f)

Cash flows

The Company expects to contribute $2,309 to its pension plans and $1,311 to its postretirement benefit plans in 2013.

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


	2013		2014		2015		2016		2017		2018- 2022
Pension plan	$	4,269	$	4,590	$	4,693	$	4,973	$	5,262	$	28,635
OPEB		1,311		1,416		1,520		1,588		1,663		10,008

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2012 and 2011

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

12.

Other assets

Other assets consist of the following:


	2012			2011
Restricted cash	$	7,063		$	4,693
Deferred financing costs		8,706			8,503
Other		3,981			4,410

		19,750			17,606
Less: current portion		(833	)		(833	)

	$	18,917		$	16,773

13.

Other long-term liabilities

Other long-term liabilities consist of the following:


	2012			2011
Asset retirement obligations	$	7,088		$	—
Customer deposits		5,620			2,483
Provision for injury and damages		3,480			—
Deferred water rights inducement		2,845			2,927
Contingent consideration		1,031			1,080
Capital Leases:
Obligation for equipment leases. Interest rates varying from 1.90% to 5.80%, monthly interest and principal payments with varying dates of maturity from March 2012 to December 2014		270			501
Other		4,907			5,073


		25,241			12,064
Less: current portion		(4,352	)		(1,037	)


	$	20,889		$	11,027

In conjunction with recent acquisitions, the Company assumed certain asset retirement obligations. These obligations have remained substantially unchanged since the acquisition date, except for normal accretion adjustments. The asset retirement obligations mainly relate to legal requirements to: (i) remove wind farm facilities upon termination of land leases; (ii) cut (disconnect from the distribution system), purge (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 dispose of sections of gas main when 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.

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2012 and 2011

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

14.

Shareholders’ capital

(a)

Common shares

Number of common shares:


	2012		2011
Common shares, beginning of period		136,122,780		95,422,778
Public offering (i)		—		16,869,000
Conversion and redemption of convertible debentures (ii)		24,991,784		15,300,824
Conversion of subscription receipts (iii)		26,380,750		8,523,000
Issuance of shares under the dividend reinvestment and employee share purchase plans (iv) and (c(ii))		1,268,172		7,178

Common shares, end of period		188,763,486		136,122,780

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, of which none are authorized or outstanding.

On June 23, 2010, the Company’s shareholders adopted a shareholders’ rights plan (the “Rights Plan”). The Rights Plan has an initial 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.

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 of Directors of APUC.

(i)

Public offering

In 2011, the Company issued 16,869,000 common shares at $5.65 per share pursuant to a public offering for proceeds of $95,310, net of issuance costs of $4,162.

(ii)

Conversion and redemption of convertible debentures

In 2011, the remaining principal amount of $62,470 of Series 1A Debentures were redeemed for 15,219,641 common shares of APUC.

In 2012, the remaining principal amount of $59,957 (2011 - $10) of Series 2A Debentures were redeemed for 10,322,518 (2011 - 1,666) common shares of APUC.

In 2012, $61,611 (2011 - $334) of Series 3 Debentures were redeemed for 14,669,266 (2011 - 79,517) shares of APUC. Subsequent to year-end, the remaining principal amount of $960 Series 3 Debentures were redeemed for 150,816 common shares of APUC.

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2012 and 2011

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

14.

Shareholders’ capital (continued)

(a)

Common shares (continued)

(iii)

Subscription receipts

In January 2011, in connection with the acquisition of Calpeco, the Company issued 8,523,000 common shares at a price of $3.25 per share to Emera pursuant to a subscription receipt agreement. The $27,700 cash proceeds of the subscription receipts were used to fund a portion of the cost of the acquisition.

On May 14, 2012, in connection with the acquisition of Granite State and EnergyNorth, the Company issued 12,000,000 common shares at a price of $5.00 per share to Emera Inc. (“Emera”) pursuant to a subscription receipt agreement. The $60,000 cash proceeds of the subscription receipts were used to fund a portion of the cost of the acquisitions.

On June 29, 2012, in connection with the acquisition of Sandy Ridge the Company received $15,000 from Emera relating to 2,614,006 subscription receipts representing a price of $5.74 per share and issued common shares relating to these subscription receipts in July 2012.

On July 31, 2012, in connection with the acquisition of the Midwest Gas Utilities the Company issued 6,976,744 common shares at a price of $6.45 per share to Emera pursuant to a subscription receipt agreement. The $45,000 cash proceeds of the subscription receipts were used to fund a portion of the cost of the acquisition.

On December 10, 2012, in connection with the acquisition of Senate and Minonk, the Company received $45,000 from Emera relating to the exercise of 7,842,016 subscription receipts at a price of $5.74 per subscription receipt pursuant to a subscription receipt agreement. The subscription receipts were converted to common shares subsequent to year end on February 14, 2013. The $45,000 cash proceeds of the subscription receipts were used to fund a portion of the cost of the acquisition.

On December 21, 2012, in connection with the acquisition of Emera’s noncontrolling interest in Calpeco, the Company received $38,756 from Emera related to the exercise of 8,211,000 subscription receipts at a price of $4.72 per subscription receipt pursuant to a subscription receipt agreement. The $38,756 proceeds of the subscription receipts were used to fund the purchase of the noncontrolling interest. On December 27, 2012, Emera exercised 4,790,000 of these subscription receipts and the Company issued 4,790,000 common shares in exchange. Subsequent to year end, on February 14, 2013, the balance of 3,421,000 subscription receipts were exercised by Emera and the Company issued 3,421,000 common shares.

Following the above noted subscription receipts transactions, as of December 31, 2012 all subscriptions receipts had been exercised for cash and 11,263,016 of those subscriptions receipts had yet to be converted to the same number of common shares.

Subsequent to year end, on February 22, 2013, in connection with the proposed acquisition of the Georgia Utility, the Company agreed to issue 3,960,000 subscription receipts convertible into the same number of common shares upon conditions based on the acquisition of the Georgia Utility at a price of $7.40 per share to Emera.

(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 will be purchased in the open market or will be 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 324,051 shares under the dividend reinvestment plan.

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2012 and 2011

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

14.

Shareholders’ capital (continued)

(b)

Preferred shares

APUC is authorized to issue an unlimited number of preferred shares, issuable in one or more series, containing terms and conditions as approved by the Board of Directors of APUC. On November 9, 2012, APUC issued 4,800 Series A Preferred shares, at a price of $25 per share, for aggregate proceeds of $120,000 before issuance cost of $4,700.

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 of Directors of APUC (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.

(c)

Share-based compensation

For the year ended December 31, 2012, APUC recorded $1,833 (2011 - $732) in total share-based compensation expense detailed as follows:


	2012		2011
Stock options	$	1,376	$	690
Directors deferred share units		155		—
Employee share purchase		42		9
Performance share units		260		33

Total share-based compensation	$	1,833	$	732

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2012 and 2011

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

14.

Shareholders’ capital (continued)

(c)

Share-based compensation (continued)

No tax deduction was realized in the current year. The compensation expense is recorded as part of administrative expenses in the Consolidated Statement of Operations. The portion of share-based compensation costs capitalized as cost of construction is insignificant.

As at December 31, 2012, total unrecognized compensation costs related to non-vested options and share unit awards were $1,724 and $219 respectively, and are expected to be recognized over a period of 1.67 years and 1.80 years respectively.

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 historic 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.

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2012 and 2011

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

14.

Shareholders’ capital (continued)

(c)

Share-based compensation (continued)

Stock option plan (continued)

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


	2012			2011
Risk-free interest rate		1.7	%		3.0	%
Expected volatility		38	%		30	%
Expected dividend yield		4.4	%		5.3	%
Expected life		8 years			8 years

Weighted average grant date fair value per option	$	1.49		$	0.99

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, 2012		2,487,105	$	4.76		6.96	$	4,134
Granted		1,263,622		6.24		8.00		—

Balance at December 31, 2012		3,750,727	$	5.25		6.07	$	5,939

Exercisable at December 31, 2012		1,215,770	$	4.53		5.85	$	2,805

Non-vested stock option activity during the period is as follows:


	Number of awards		Weighted Average Grant Date Fair value
Non-vested options at January 1, 2012		2,100,369	$	0.85
Granted		1,263,622		1.49

Vested		829,035		0.81

Non-vested options at December 31, 2012		2,534,956	$	1.18

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2012 and 2011

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

14.

Shareholders’ capital (continued)

(c)

Share-based compensation (continued)

ii)

Employee share purchase plan

Under the Company’s employee share purchase plan (“ESPP”), eligible employees may have a portion of their earnings withheld to be used to purchase the Company’s common shares. The Company will match a) 20% of the employee contribution amount for the first five thousand dollars per employee contributed annually and 10% of the employee contribution amount for contributions over five thousand dollars up to ten thousand dollars annually, for Canadian employees, and b) 15% of the employee contribution amount for the first fifteen thousand dollar per employee contributed annually, for U.S. employees. 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 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 shares reserved for issuance from treasury by APUC under this plan shall not exceed 2,000,000 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, 2012, a total of 54,227 common shares (2011 – 7,176) were issued to employees under the ESPP plan.

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 Deferred Share Units (“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 share. 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. In 2012, 50,172 (2011 – nil) DSUs were issued pursuant to the election of the Directors to defer a percentage of their 2011 and 2012 Director’s fee in the form of DSUs.

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. Performance share units (“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 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 dividend’s are declared. None of these PSUs have voting rights. Any PSUs not vested at the end of a performance period will expire. The PSUs provide for settlement in cash or shares at the election of the Company. As the Company does not expect to settle these instruments in cash, these PSUs will be accounted for as equity awards. Compensation expense associated with PSUs is recognized ratably over the performance period based on the Company’s estimated achievement of the established metrics. Compensation expense for awards with performance conditions will only be recognized for those awards for which it is probable that the performance conditions will be achieved and which are expected to vest.

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2012 and 2011

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

14.

Shareholders’ capital (continued)

(c)

Share-based compensation (continued)

iv)

Performance share units (continued)

A summary of the PSUs follows; none of which are exercisable as at December 31, 2012:


	Number of awards			Weighted Average Grant-Date Fair Value		Weighted Average Remaining Contractual Term (years)		Aggregate intrinsic value
January 1, 2011		—		$	—		—		—
Granted		21,123			5.62		2.0		118,649

December 31, 2011		21,123		$	5.62		2.0		135,610
Granted, including dividends		68,982			6.78		1.3		467,518
Forfeited		(6,622	)		5.62		1.5		(37,196	)

December 31, 2012		83,483		$	6.58		1.8		571,025

15.

Accumulated other comprehensive loss

Accumulated other comprehensive loss is comprised of the following balances, net of tax:


	2012			2011
Foreign currency cumulative translation adjustment	$	(105,959	)	$	(96,462	)
Unrealized gain on cash flow hedges		3,593			—
Pension and post-retirement actuarial loss		(2,501	)		(48	)

Total	$	(104,867	)	$	(96,510	)

16.

Cash dividends

All dividends of the Company are made on a discretionary basis as determined by the Board of the Company. For the year ended December 31, 2012, the Company declared dividends to shareholders on common shares totaling $50,193 of which $42,850 were cash dividends (2011 - $32,426 of which were cash dividends) or $0.295 per common share (2011 - $0.24 per common share). The Board declared a dividend on the Company’s common shares of $0.0775 per share payable on January 15, 2013 to the shareholders of record on December 31, 2012.

On December 31, 2012, an initial dividend of $0.1603 per share totaling $769, Series A, was paid in cash to Preferred Share, Series A holders of record on December 17, 2012.

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2012 and 2011

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

17.

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% (2011 – 28.25%). The differences are as follows:


	2012			2011
Expected income tax expense / (recovery) at Canadian statutory rate	$	2,527		$	1,555
Increase (decrease) resulting from:
Recognition of deferred credit		(5,092	)		(6,581	)
Effect of differences in tax rates on transactions in and within foreign jurisdictions and change in tax rates		(6,282	)		(1,592	)
Non-taxable corporate dividend		(666	)		(591	)
Non-controlling interests share of income		(2,835	)		(1,317	)
Production tax credit		(676	)		—
Allowance for equity funds used during construction		(402	)		—
Change in valuation allowances		—			(16,834	)
Foreign currency on intercompany items		—			2,250
Other		(140	)		563

Income tax recovery	$	(13,566	)	$	(22,547	)

For the years ended December 31, 2012 and 2011, income/(loss) from continuing operations before taxes consists of the following:


	2012			2011
Canadian operations	$	15,252		$	(5,242	)
U.S. operations		(5,715	)		10,749

	$	9,537		$	5,507

As a result of the business combination transaction in 2009, APUC recorded certain additional tax attributes. These tax attributes have been recognized to the extent management believes they are more likely than not to be realized. The excess of the carrying amount of the tax attributes recorded over the consideration was recorded as a deferred credit of $55,647 on the transaction date. The deferred credit is being recognized in income as a deferred income tax recovery in relative proportion to the amount of the related tax attributes that are utilized in the period.

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


	Current		Deferred			Total
Year ended December 31, 2012
Canada	$	127	$	(137	)	$	(10	)
United States		611		(14,167	)		(13,556	)

	$	738	$	(14,304	)	$	(13,566	)

Year ended December 31, 2011
Canada	$	268	$	(1,936	)	$	(1,668	)
United States		32		(20,911	)		(20,879	)

	$	300	$	(22,847	)	$	(22,547	)

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2012 and 2011

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

17.

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 at December 31, 2012 and 2011 are presented below:


	2012			2011
Deferred tax assets:
Non-capital loss, investment tax credits, currently non-deductible interest expenses, and financing costs	$	184,845		$	119,340
Outside basis in partnership		2,533			—
Financial derivatives		211			2,233
Pension and OPEB		5,011			—
Acquisition related costs		5,134			2,009
Regulatory accounts		9,407			4,313
Production tax credit		673			—
Reserves not currently deductible		1,276			—
Other		136			—

Total deferred income tax assets		209,226			127,895

Less: Valuation allowance		(15,062	)		(15,062	)

Total deferred tax assets		194,164			112,833

Deferred tax liabilities:
Property, plant and equipment		(202,553	)		(77,273	)
Intangible assets		(5,478	)		(7,812	)
Other		—			(1,009	)

Total deferred tax liabilities		(208,031	)		(86,094	)

Net deferred tax assets/(liabilities)	$	(13,867	)	$	26,739

The valuation allowance for deferred tax assets as of December 31, 2012 and 2011 was $15,062. The net change in the total valuation allowance was nil in 2012 and a decrease of $16,834 in 2011. The valuation allowance at December 31, 2012 was primarily related 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:


	2012			2011
Current deferred income tax asset	$	10,567		$	13,022
Non-current deferred income tax asset		77,497			67,671
Current deferred income tax liability		(1,133	)		(723	)
Non-current deferred income tax liability		(100,798	)		(53,231	)

	$	(13,867	)	$	26,739

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2012 and 2011

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

17.

Income taxes (continued)

As at December 31, 2012, 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 losses carry forwards
2015	$	5,426
2026 and onwards		390,633

	$	396,059

18.

Sale of Small U.S. Hydro Facilities

On March 14, 2013, APCo entered into an agreement to sell 10 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. $27,000. In August 2012, APCo sold another small U.S. Hydro facility for gross proceeds of $350 for a loss on sale, net of tax of $253 which is included in the loss from discontinued operations. The operating results from these facilities are therefore disclosed as discontinued operations on the consolidated statements and prior periods have been reclassified to conform to this presentation.

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


	2012			2011
Non-regulated energy sales		2,870			5,921
Operating and administrative expenses		3,241			4,402
Depreciation of property, plant and equipment		1,279			1,405
Interest expense		4			4
Loss on sale of assets		253			—
Write-down of long-lived assets		—			1,354


Loss from discontinued operations, before income taxes		(1,907	)		(1,244	)
Income tax recovery		750			492


Loss from discontinued operations, net of income taxes		(1,157	)		(752	)
Add:
Depreciation of property, plant and equipment		1,279			1,405
Loss on sale of assets		253			—
Write-down of long-lived assets		—			1,354
Less:
Income tax recovery		(750	)		(492	)


Net cash (outflow) inflow from discontinued operations		(375	)		1,515

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


	2012		2011
Property, plant and equipment		24,390		25,847

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2012 and 2011

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

19.

Related party transactions

Certain executives of APUC are shareholders of Algonquin Power Management Inc. (“APMI”), the former manager of the Company. A member of the Board of Directors of APUC is an executive at Emera.

Transactions with APMI and Senior Executives

APUC has leased its head office facilities since 2001 from an entity owned by the shareholders of APMI on a triple net basis. Base lease costs for the year ended December 31, 2012 were $333 (2011 - $327).

APUC utilizes chartered aircraft, including the use of an aircraft owned by an affiliate of APMI, Algonquin Airlink Inc. In 2004, APUC remitted $1,300 to the affiliate as an advance against expense reimbursements (including engine utilization reserves) for APUC’s business use of the aircraft. During the year ended December 31, 2012, APUC incurred costs in connection with the use of the aircraft of $598 (2011 - $453) and amortization expense related to the advance against expense reimbursements of $279 (2011 - $274). At December 31, 2012, the remaining amount of the advance was $nil (December 31, 2011 - $279).

Affiliates of APMI hold 60% of the outstanding Class B limited partnership units issued by the St. Leon LP, a subsidiary of APUC and the legal owner of the St. Leon facility. The related holders of the Class B units received cash distributions of $292 for the year ended December 31, 2012 (2011 - $314). Subsequent to year-end, on January 1, 2013, the Company issued 100 redeemable Series C preferred shares and exchanged such shares for the Class B units (notes 13 and 14 (b)).

APUC provided supervisory management services on a cost recovery basis to a hydroelectric generating facility not owned by APUC where Senior Executives hold an equity interest.

Rattle Brook is a hydroelectric generating facility in which APUC owns a 45% interest and Senior Executives hold an equity interest in. Rattle Brook is operated on a cost recovery basis by an entity which is partially owned by Senior Executives.

APMI is one of the two original developers of Red Lily I and both developers are entitled to a royalty fee based on a percentage of operating revenue and a development fee from the equity owner of Red Lily I. In 2011, APUC acquired APMI’s interest in this royalty for an amount of $600.

As part of the project to re-power the Sanger facility, APUC entered into an agreement with APMI to undertake certain construction management services on the project for a performance based contingency fee. An amount of U.S. $550 has been accrued as an estimate of the final fee owed to APMI.

During 2007, APUC allowed its offer to acquire Clean Power Income Fund to expire and earned a termination fee of $1,800. As part of its role in the process, APUC has agreed to pay APMI a fee of U.S. $100 which has been accrued as an estimate of the final fee owed to APMI.

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2012 and 2011

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

19.

Related party transactions (continued)

Transactions with APMI and Senior Executives (continued)

As at December 31, 2012, included in amounts due from related parties is $816 (2011 - $663) owed to APUC from APMI and included in amounts due to related parties is $1,811 (2011 - $1,795) owed to APMI. These amounts arise from the transactions described above.

Long Sault is a hydroelectric generating facility in which APUC acquired its interest by way of subscribing to two notes from the original developers. An affiliate of APMI is one of the original partners in the facility and is entitled to receive 5% of the after tax equity cash flows commencing in 2014.

In March, 2012, APUC and APMI’s Senior Executives (the “Parties”) reached a term sheet agreement to resolve a number of the historic joint business associations between the Parties. The transaction is subject to finalization of definitive agreements which are expected to be completed in the first quarter of 2013.

Under the term sheet, it is proposed that APUC will exchange its 45% interest in the 4MW Rattlebrook hydroelectric facility (including a $0.5 million positive working capital adjustment) in return for the Parties’ residual partnership interest in the Long Sault Rapids hydroelectric facility and the equity interest in the Brampton cogeneration plant. The agreement also settles outstanding fees owing to APMI.

Transactions with Emera

In 2011, a subsidiary of Emera provided lead market participant services for fuel capacity and forward reserve markets in ISO NE for the Windsor Locks facility. During the year ended December 31, 2012 APUC paid U.S. $nil (2011 – U.S. $260) in relation to this contract. In 2011, APUC provided a corporate guarantee to a subsidiary of Emera in an amount of U.S. $1,000 in conjunction with this contract.

For the year ended December 31, 2012, the Energy Services Business sold electricity to Maine Public Service Company (“MPS”), a subsidiary of Emera, amounting to U.S. $6,096 (2011 – U.S. $6,564). 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.

As of December 31, 2012, included in amounts due from related parties is $nil (2011 - $1,612) owed from Emera related to the unpaid contribution of their share of Liberty Energy (California) costs.

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

20.

Basic and diluted net earnings per share

Basic and diluted earnings per share have been calculated on the basis of net earnings attributable to the common shareholders of the Company and the weighted average number of common shares outstanding during the year. Diluted net income per share is computed using the weighted-average number of common shares and, if dilutive, potential common shares outstanding during the period. Potential common shares consist of the incremental common shares issuable upon the exercise of stock options, PSUs, DSUs, shareholders’ rights and convertible debentures. The dilutive effect of outstanding stock options, PSUs, DSUs and shareholders’ rights is reflected in diluted earnings per share by application of the treasury stock method while the dilutive effect of convertible debentures is reflected in diluted earnings per share by application of the as if converted method.

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2012 and 2011

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

20.

Basic and diluted net earnings per share (continued)

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


	2012		2011
Net earnings attributable to shareholders of APUC	$	14,532	$	23,381
Preferred shares dividend		769		—


Net earnings attributable to common shareholders of APUC – Basic and Diluted	$	13,763	$	23,381

Weighted average number of shares

Basic		158,304,340		116,712,934
Dilutive effect of share-based awards		605,281		249,854


Diluted		158,909,621		116,962,788

The shares potentially issuable as a result of the convertible debentures as well as stock options of 1,354,531 respectively (2011 – 1,326,900) are excluded from this calculation as they are anti-dilutive.

21.

Commitments and contingencies

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.

On October 21, 2011 the Québec Court of Appeal ordered a subsidiary of APUC to pay approximately $5,400 (including interest) to the government of Québec 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 $5,800. In 2012, the Company paid an amount of $1,884 (2011 - $ nil) to the government of Québec 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, 2012 and 2011

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

21.

Commitments and contingencies

(a)

Contingencies

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 and the New Hampshire Department of Environmental Services (“NHDES”). Like most other industrial companies, the gas and electric distribution utilities generate some hazardous wastes. Under federal and state Superfund 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 Liberty Utilities, EnergyNorth and Granite State 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 NHDES. The Company believes that obligations imposed on it because of those sites will not have a material impact on its results of operations or financial position.

The Company estimates the remaining undiscounted, unescalated cost of these MGP-related environmental cleanup activities will be $59,862 (U.S. $60,168) which at a discount rate of 3.5% represents the recorded accrual of $56,587 at December 31, 2012. This amount reflects the approval from the NHDES on December 10, 2012 of a Conceptual Remedial Design Report submitted to NHDES for removal of tar-impacted media at the Liberty Hill Road Site in New Hampshire. The NHDES approval at Liberty Hill Road Site reduced the overall cost estimate and consequently the Company withdrew its pending appeal. Remediation costs estimates for each site may vary, depending upon changing technologies and regulatory standards, selected end use for each site, and actual environmental conditions encountered.

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, at December 31, 2012 the Company has reflected a regulatory asset of $59,789 for the MGP and related sites.

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


2013	$	2,433
2014		13,316
2015		18,836
2016		14,236
2017		996
Thereafter to 2046		10,045

	$	59,862

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2012 and 2011

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

21.

Commitments and contingencies

Commitments (continued)

In addition to the commitments related to the proposed acquisitions disclosed in note 3 the following significant commitments exist at December 31, 2012.

As a result of the dam safety legislation passed in Quebec (Bill C93), 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 $16,900 over a period of five years related to compliance with the legislation.

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


	Year 1		Year 2		Year 3		Year 4		Year 5		Thereafter		Total
Purchased power	$	56,276	$	42,999	$	41,316	$	—	$	—	$	—	$	140,591

Gas delivery, service and supply agreements		25,165		16,792		14,977		5,777		5,207		52,461		120,379

Service agreements		27,147		18,610		17,827		22,253		23,023		566,903		675,763

Capital projects		3,110		500		—		—		—		—		3,610

Operating leases		4,405		4,099		3,792		3,284		3,202		69,562		88,344


Total	$	116,103	$	83,000	$	77,912	$	31,314	$	31,432	$	688,926	$	1,028,687

Calpeco 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, 2012. However, the effects of purchased power unit cost adjustments are mitigated through a purchased power rate-adjustment mechanism. Granite State 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.

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2012 and 2011

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

22.

Non-cash operating items

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


	2012			2011
Accounts receivable	$	(14,895	)	$	(11,674	)
Related party balances		1,476			145
Supplies and consumable inventory		(3,621	)		(1,087	)
Income tax receivable		(423	)		(133	)
Prepaid expenses		(4,629	)		(2,071	)
Accounts payable		(7,553	)		3,991
Accrued liabilities		31,105			9,010
Current income tax liability		131			207
Net regulatory assets and liabilities		(5,475	)		70

	$	(3,884	)	$	(1,542	)

23.

Segmented information

APUC has two operating segments: APCo which owns or has interests in renewable energy facilities and thermal energy facilities and Liberty Utilities which owns and operates utilities in the United States of America providing water, wastewater and local electric and natural gas distribution services.

Within APCo there are three divisions: Renewable Energy, Thermal Energy and Development. The Renewable Energy division operates the Company’s hydro-electric and wind power facilities. The Thermal Energy division operates co-generation, energy from waste, steam production and other thermal facilities. The Development division develops the Company’s greenfield power generation projects as well as any expansion of the Company’s existing portfolio of renewable energy and thermal energy facilities.

Effective July 2012, the Company changed its operational segments within Liberty Utilities to be aggregated and reported by the following geographic territories: Liberty Utilities (West), Liberty Utilities (Central) and Liberty Utilities (East). Liberty Utilities (West) is comprised of Calpeco and the water distribution and wastewater utilities located in Arizona. Liberty Utilities (Central) is comprised of the Midwest Gas Utilities and the water distribution and wastewater utilities located in Texas, Missouri and Illinois. Liberty Utilities (East) is comprised of the New Hampshire electric and gas utilities. The Company has restated the comparative items of segmented financial information to reflect the aggregation of segmented financial information adopted in the current year.

Operational segments

APUC’s reportable segments are APCo - Renewable Energy, APCo - Thermal Energy, Liberty Utilities (West), Liberty Utilities (Central) and Liberty Utilities (East). The development activities of APCo are reported under Renewable Energy or Thermal Energy as appropriate. For purposes of evaluating divisional performance, the Company allocates the realized portion of the loss on financial instruments to specific divisions. This allocation is determined when the initial foreign exchange forward contract is entered into. The unrealized portion of any gains or losses on derivatives instruments is not considered in management’s evaluation of divisional performance and is therefore allocated and reported in the corporate segment. The interest rate swaps relate to specific debt facilities and gains and losses are allocated in the same manner as interest expense. Amounts relating to the convertible debentures are reported in the corporate segment.

The results of operations and assets for these segments are as follows:

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2012 and 2011

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

23.

Segmented information (continued)

Operational segments (continued)


	Year ended December 31, 2012
	Algonquin Power												Liberty Utilities									Corporate			Total
	Renewable Energy			Thermal Energy			Total			Central			West			East			Total
Revenue
Regulated electricity sales and distribution	$	—		$	—		$	—		$	—		$	71,734		$	36,723		$	108,457		$	—		$	108,457
Regulated gas sales and distribution		—			—			—			25,802			—			49,916			75,718						75,718
Regulated water reclamation and distribution		—			—			—			9,127			37,296			—			46,423			—			46,423
Non-regulated energy sales		84,236			36,914			121,150			—			—			—			—			—			121,150
Waste disposal fees		—			14,288			14,288			—			—			—			—			—			14,288
Other revenue		1,925			1,680			3,605			—			152			94			246			—			3,851

Total revenue		86,161			52,882			139,043			34,929			109,182			86,733			230,844			—			369,887

Operating expenses		30,308			21,075			51,383			13,096			35,645			30,209			78,950			—			130,333
Regulated electricity purchased		—			—			—			—			43,861			24,348			68,209			—			68,209
Regulated gas purchased		—			—			—			13,648			—			23,813			37,461			—			37,461
Non-regulated fuel for generation		—			14,589			14,589			—			—			—			—			—			14,589

		55,853			17,218			73,071			8,185			29,676			8,363			46,224			—			119,295

Depreciation of property, plant and equipment		(18,823	)		(9,977	)		(28,800	)		(3,333	)		(11,120	)		(7,129	)		(21,582	)		—			(50,382	)
Amortization of intangible assets		(2,653	)		(831	)		(3,484	)		(81	)		(586	)		—			(667	)		—			(4,151	)
Administration expenses		(9,424	)		(2,212	)		(11,636	)		294			(4,091	)		(1,223	)		(5,020	)		(2,952	)		(19,608	)
Foreign exchange gain		—			—			—			—			—			—			—			561			561
Interest expense		(15,060	)		(2,054	)		(17,114	)		(96	)		(8,066	)		(694	)		(8,856	)		(9,971	)		(35,941	)
Interest, dividend and other income		2,038			509			2,547			—			2,113			461			2,574			2,118			7,239
Acquisition related costs		(3,155	)		—			(3,155	)		(1,442	)		—			(3,112	)		(4,554	)		—			(7,709	)
Gain/(loss) on derivative financial instruments		(2,954	)		—			(2,954	)		—									—			3,187			233

Earnings from continuing operations before income taxes		5,822			2,653			8,475			3,527			7,926			(3,334	)		8,119			(7,057	)		9,537
Loss from discontinued operations before income taxes		(1,907	)		—			(1,907	)		—			—			—			—			—			(1,907	)

Earnings/(loss) before income taxes	$	3,915		$	2,653		$	6,568		$	3,527		$	7,926		$	(3,334	)	$	8,119		$	(7,057	)	$	7,630

Property, plant and equipment	$	1,157,062		$	153,875		$	1,310,937		$	151,637		$	350,053		$	350,088		$	851,778		$	—		$	2,162,715
Intangible assets		29,480			6,132			35,612			2,613			18,556			—			21,169			—			56,781
Assets held for sale		24,390			—			24,390			—			—			—			—			—			24,390
Total assets		1,272,037			175,173			1,447,210			212,495			464,201			500,374			1,177,070			153,957			2,778,237
Capital expenditures		21,068			10,348			31,416			10,777			23,181			12,488			46,446			67			77,929
Acquisition of operating entities		245,718			—			245,718			128,890			—			295,297			424,187			—			669,905

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2012 and 2011

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

23.

Segmented information (continued)

Operational segments (continued)


	Year ended December 31, 2011
	Algonquin Power												Liberty Utilities								Corporate			Total
	Renewable Energy			Thermal Energy			Total			Central			West			East		Total
Revenue
Regulated electricity sales and distribution	$	—		$	—		$	—		$	—		$	77,368		$	—	$	77,368		$	—		$	77,368
Regulated water reclamation and distribution		—			—			—			8,850			36,139			—		44,989			—			44,989
Non-regulated energy sales		81,645			46,666			128,311			—			—			—		—			—			128,311
Waste disposal fees		—			16,406			16,406			—			—			—		—			—			16,406
Other revenue		2,291			1,352			3,643			—			—			—		—			—			3,643

Total revenue		83,936			64,424			148,360			8,850			113,507			—		122,357			—			270,717

Operating expenses		25,400			19,857			45,257			4,270			34,453			—		38,723			38			84,018
Regulated electricity purchased		—			—			—			—			46,508			—		46,508			—			46,508
Non-regulated fuel for generation		—			24,628			24,628			—			—			—		—			—			24,628

		58,536			19,939			78,475			4,580			32,546			—		37,126			(38	)		115,563

Depreciation of property, plant and equipment		(15,498	)		(10,684	)		(26,182	)		(956	)		(10,850	)		—		(11,806	)		—			(37,988	)
Amortization of intangible assets		(3,007	)		(2,735	)		(5,742	)		(81	)		(610	)		—		(691	)		—			(6,433	)
Administration expenses		(8,915	)		(2,504	)		(11,419	)		(53	)		(1,087	)		—		(1,140	)		(4,975	)		(17,534	)
Write down of long-lived assets		(678	)		(13,430	)		(14,108	)					(1,058	)				(1,058	)		—			(15,166	)
Foreign exchange loss		—			—			—			—			—			—		—			652			652
Interest expense		(9,834	)		(2,228	)		(12,062	)		(61	)		(7,404	)		—		(7,465	)		(10,910	)		(30,437	)
Interest, dividend and other income		2,143			(6	)		2,137			—			488			—		488			3,034			5,659
Acquisition related costs		—			—			—			—			(2,767	)		—		(2,767	)		(198	)		(2,965	)
Loss on derivative financial instruments		(1,068	)		—			(1,068	)		—			—			—		—			(4,776	)		(5,844	)

Earnings from continuing operations before income taxes		21,679			(11,648	)		10,031			3,429			9,258			—		12,687			(17,211	)		5,507
Loss from discontinued operations before income taxes		(1,244	)		—			(1,244	)		—			—			—		—			—			(1,244	)

Earnings/(loss) before income taxes	$	20,435		$	(11,648	)	$	8,786		$	3,429		$	9,258		$	—	$	12,687		$	(17,211	)	$	4,263

Property, plant and equipment	$	398,037		$	155,507		$	553,544		$	188,562		$	178,003		$	—	$	366,565		$	—		$	920,109
Intangible assets		25,863			7,088			32,951			19,565			2,753			—		22,318			—			55,269
Assets held for sale		25,847			—			25,847			—			—			—		—			—			25,847
Total assets		482,543			176,269			658,812			228,597			212,035			—		440,632			182,863			1,282,307
Capital expenditures		25,610			13,601			39,211			774			20,393			—		21,167			367			60,745
Acquisition of operating entities		—			—			—			—			100,058			—		100,058			—			100,058

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2012 and 2011

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

23.

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 2012 or 2011: Hydro Québec 17% (2011 - 17%), Manitoba Hydro 20% (2011 – 16%), and California PG&E 10% (2011 - 11%). The Company has mitigated its credit risk to the extent possible by selling energy to these large utilities in various North American locations.

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


	2012		2011
Revenue
Canada	$	83,117	$	88,900
United States		286,770		181,817

	$	369,887	$	270,717
Property, plant and equipment
Canada	$	472,333	$	474,094
United States		1,690,382		446,015

	$	2,162,715	$	920,109
Intangible assets
Canada	$	29,480	$	25,863
United States		27,301		29,406

	$	56,781	$	55,269

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

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2012 and 2011

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

24.

Financial instruments

(a)

Fair value of financial instruments


			2012
	Carrying amount		Fair Value		Level 1		Level 2		Level 3
Notes receivable	$	22,937	$	25,476	$	—	$	—	$	25,476
Derivative financial instruments:
Energy contracts designated as a cashflow hedge		12,695		12,695		—		12,695		—
Cross-currency swap designated as a foreign exchange hedge		408		408		—		408		—
Commodity contracts for regulatory operations		147		147		—		147		—

Total derivative financial instruments		13,250		13,250				13,250

Total financial assets	$	36,187	$	38,726	$	—	$	13,250	$	25,476

Long-term liabilities	$	770,826	$	785,473	$	—	$	785,473	$	—
Convertible debentures		960		1,319		1,319		—		—
Derivative financial instruments:
Energy contracts designated as a cashflow hedge		9,012		9,012		—		9,012		—
Cross-currency swap designated as a foreign exchange hedge		2,078		2,078		—		2,078		—
Interest rate swaps not designated as a hedge		4,778		4,778		—		4,778		—
Energy derivative contracts		287		287		—		287		—
Commodity contracts for regulated operations		1,661		1,661		—		1,661		—

Total derivative financial instruments		17,816		17,816		—		17,816

Total financial liabilities	$	789,602	$	804,608	$	1,319	$	803,289	$	—

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2012 and 2011

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

24.

Financial instruments (continued)

(a)

Fair value of financial instruments (continued)


			2011
	Carrying amount		Fair Value		Level 1		Level 2		Level 3
Notes receivable	$	24,534	$	24,534	$	—	$	—	$	24,534

Total financial assets	$	24,534	$	24,534	$	—	$	—	$	24,534

Long-term liabilities	$	332,716	$	338,264	$	—	$	338,264	$	—
Convertible debentures		122,297		162,195		162,195		—		—
Derivative financial instruments:
Interest rate swaps not designated as a hedge		6,975		6,975		—		6,975		—
Energy derivative contracts		1,169		1,169		—		1,169		—

Total derivative financial instruments		8,144		8,144		—		8,144		—

Total financial liabilities	$	463,157	$	508,603	$	162,195	$	346,408	$	—

•

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

•

The Company has determined that the carrying value of its short-term financial assets and liabilities approximates fair value (a level 2 measurement) at December 31, 2012 and 2011 due to the short-term maturity of these instruments.

Notes receivable fair values 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. Such estimate is significantly influenced by unobservable data and therefore this fair value is subject to estimation risk.

APUC has long-term liabilities at fixed interest rates and variable rates. The estimated fair value is calculated using current interest rates. The fair value of convertible debentures is determined using quoted market price.

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2012 and 2011

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

24.

Financial instruments (continued)

(a)

Fair value of financial instruments (continued)

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 8.5%. 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, 2012 or 2011.

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, 2012 or 2011.

(b)

Derivative instruments

Derivative instruments are recognized on the balance sheet 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 accounting for these derivative instruments is subject to current 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 accompanying balance sheets. Gains or losses on the settlement of these contracts are included in the calculation of deferred gas costs (note 7 (v)).

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


	2012
Financial contracts: Gas swaps		3,353,420
Gas options		787,960


		4,141,380

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2012 and 2011

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

24.

Financial instruments (continued)

(b)

Derivative instruments (continued)

(i)

Commodity derivatives – regulated accounting (continued)

The change in fair value of the derivative instruments is recorded as an offsetting adjustment to regulatory assets and liabilities. 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 accompanying balance sheets:


	2012		2011
Regulatory assets:
Gas swap contracts	$	1,555	$	—
Gas option contracts	$	106	$	—

Regulatory liabilities:
Gas swap contracts	$	90	$	—
Gas option contracts	$	57	$	—

(ii)

Cash flow hedges

APCo reduces the price risk on the expected future sale of power generation at Sandy Ridge, Senate and Minonk 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)
	196,231	May 2012 – December 2016	U.S. $	66.57	AESO
	1,144,045	January 2013 – December 2022	U.S. $	42.81	PJM Western HUB
	4,885,898	January 2013 – December 2022	U.S. $	30.25	NI HUB
	4,995,968	January 2013 – December 2027	U.S. $	36.46	ERCORT North HUB

The effects on the Consolidated Statement of Operations of derivative financial instruments designated as cash flow hedge consist of the following:


	2012		2011
Gain on derivative instruments (ineffective portion)	$	105	$	—

The following table summarizes changes in other comprehensive income attributable to derivative financial instruments designated as a hedge:


	2012			2011
Effective portion of cash flow hedge, gain	$	5,214		$	—
Gain (loss) realized on cash flow hedge		(49	)		—

	$	5,165		$	—
Less noncontrolling interest		(1,572	)	$	—

Change in fair value of cash flow hedge in other comprehensive income	$	3,593		$	—

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2012 and 2011

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

24.

Financial instruments (continued)

(b)

Derivative instruments (continued)

(ii)

Cash flow hedges (continued)

The Company expects $3,852 of unrealized gains currently in accumulated other comprehensive loss to be reclassified into net earnings 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 debentures offering in December 2012, APCo entered into a cross currency swap, coterminous with the debentures, to effectively convert the Canadian dollar denominated offering into U.S. dollars. APCo designated the entire notional amount of the cross currency fixed for fixed interest rate swap and related short-term USD payables created by the monthly accruals of the swap settlement as a hedge of the foreign currency exposure of its net investment in APCo’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 USD accruals that are designated as, and are effective as, an economic hedge of the net investment in a foreign operation are reported in the same manner as the translation adjustment (in other comprehensive income) related to the net investment. A foreign currency loss of $1,669 was recorded in other comprehensive income in 2012.

(iv)

Other derivatives

APCo 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 derivative instruments. In January 2011, APUC entered into electricity derivative contracts for a term ending February 2014, which are net settled fixed-for-floating swaps whereby APUC will pay a fixed price and receive the floating or indexed price on a notional quantity of 91,216 MW-hrs of energy over the remainder of the contact term at an average rate of approximately U.S. $52.89 per MW-hr. The estimated fair value of these forward energy hedge contracts at December 31, 2012 was a net liability of $286 (2011 - $1,169). These contracts are not accounted for as hedges and changes in fair value are recorded in earnings as they occur.

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2012 and 2011

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

24.

Financial instruments (continued)

(b)

Derivative instruments (continued)

(iv)

Other derivatives (continued)

For derivatives that are not designated as cash flow hedges, and for the ineffective portion of gains and losses on derivatives that are accounted as hedges the changes in the fair value are immediately recognized in earnings. The effects on the statement of operations of derivative financial instruments not designated as hedges consist of the following:


	2012			2011
Change in unrealized loss/(gain) on derivative financial instruments:
Foreign exchange contracts	$	—		$	(45	)
Interest rate swaps		(2,197	)		1,536
Energy derivative contracts		(825	)		833

Total change in unrealized loss/(gain) on derivative financial instruments	$	(3,022	)	$	2,324

Realized loss/(gain) on derivative financial instruments:
Foreign exchange contracts	$	(187	)	$	691
Interest rate swaps		2,094			2,138
Energy derivative contracts		987			691

Total realized loss on derivative financial instruments	$	2,894		$	3,520

Loss/(gain) on derivative financial instruments accounted for as hedges	$	(128	)	$	5,844

Ineffective portion of derivatives financial instruments accounted for as hedges	$	(105	)		—

Loss/(gain) on derivative financial instruments	$	(233	)	$	5,844

(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 to 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, 2012 and 2011

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

24.

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 and notes receivable. 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 Utility Services business unit which consists of water and wastewater utilities, electric utilities and gas utilities in the United States. In this regard, the credit risk related to Utility Services accounts receivable balances of U.S. $35,688 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 Company’s utilities allow for a reasonable bad debt expense to be incorporated in the rates and therefore ultimately recoverable from rate payers.

As at December 31, 2012 the Company’s maximum exposure to credit risk for these financial instruments was as follows:


	December 31, 2012
	Canadian $		US $
Cash and cash equivalents and restricted cash	$	20,452	$	39,936
Other current assets		833		—
Accounts receivable		14,904		79,680
Allowance for Doubtful Accounts		—		(4,382	)
Notes Receivable		20,747		2,201

	$	56,936	$	117,435

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2012 and 2011

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

24.

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 at December 31, 2012, in addition to cash on hand of $53,122 the Company had $224,310 available to be drawn on its senior debt facilities. The senior 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	$	1,768	$	58,490	$	14,853	$	695,715	$	770,826
Advances in aid of construction		591		—		—		71,626		72,217
Interest on long term debt		41,090		80,415		71,576		136,671		329,752
Accounts payable and due to related parties		36,094		—		—		—		36,094
Environmental obligation		2,433		32,152		15,232		10,045		59,862
Accrued liabilities		99,468		—		—		—		99,468
Derivative financial instruments:
Cross- currency swap		—		—		—		2,077		2,077
Interest rate swaps		1,968		2,810		—		—		4,778
Energy derivative and commodity contracts		245		1,703		384		8,629		10,961
Capital lease payments		134		136		—		—		270
Other obligations		4,217		3,100		380		15,972		23,669

Total obligations	$	188,008	$	178,806	$	102,425	$	940,735	$	1,409,974

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.

In August 2012, APCo designated the amounts drawn on its bank credit facility denominated in U.S. dollars as a hedge of the foreign currency exposure of its net investment in APCo’s U.S. operations. The foreign currency transaction gain or loss on the outstanding U.S. dollar denominated balance of APCo’s facility that is designated a hedge of the net investment in its foreign operations is reported in the same manner as a translation adjustment (in other comprehensive income) related to the net investment, to the extent it is effective as a hedge. A foreign currency loss of $452 was recorded in other comprehensive income.

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 facility, its interest rate swaps as well as interest earned on its cash on hand. The Company does not currently hedge that risk.

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2012 and 2011

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

24.

Financial Instruments (continued)

(c)

Risk management (continued)

Interest rate risk (continued)

APCo is party to an interest rate swap whereby, the Company pays a fixed interest rate of 4.47% on a notional amount of $64,276 and receives floating interest at 90 day CDOR, up to the expiry of the swap in September 2015. At December 31, 2012, the estimated fair value of the interest rate swap was a liability of $4,778 (2011 – liability of $6,975). 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.

25.

Subsequent event

Subsequent to year-end, 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 APCo and the legal owner of the St. Leon facility (note 19). Thirty six of the Class C preferred shares are owned by related parties controlled by executives of the Company. The preferred shares are mandatorily redeemable in 2031 have a contractual cumulative cash dividend paid quarterly based on a prescribed payment schedule out to the redemption date in 2031. Consequently, these shares will be accounted for as liabilities in the 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.

Upon redemption in 2031, the shares are to be redeemed for $53,400 per share. The Series C 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 Class C preferred shares will initially be measured at its estimated fair value of $18,205 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 $18,205 will result in an adjustment to equity of the shareholders of the Company as the Class B shares had a nominal carrying amount prior to the exchange. The preferred shares will be 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 Class C Preferred Share carrying value.


Estimated dividend and redemption payments due in the next five years and thereafter are:

2013	$	802
2014		1,078
2015		1,046
2016		919
2017		870
Thereafter to 2031, including redemption amount		26,706

Less amounts representing interest		(13,216	)

Final redemption of Class C Preferred Shares	$	18,205

26.

Comparative figures

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

Positive
Negative
Uncertain
Constraining
Legalese
Litigous
Readability	H.S. freshman Bad

Algonquin Power & Utilities (AQN) 40-F2012 FY Annual report (Canada)

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