Algonquin Power & Utilities (AQN) 40-F 2010 FY Annual report (Canada)

Exhibit 99.2

Consolidated Financial Statements of

Algonquin Power & Utilities Corp.

For the year ended December 31, 2010 and December 31, 2009

1

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 Canadian generally accepted accounting principles and reconciled to US GAAP. 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, 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 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, 2010, based on the framework established in Internal 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, 2010.

KPMG LLP, independent auditors appointed by the shareholders of the Company, has audited the consolidated financial statements of the Company for the year ended December 31, 2010, has also issued a report on the effectiveness of the Company’s internal control over financial reporting.

Date: March 31, 2011

By:	/s/ Ian E. Robertson	By:	/s/ David Bronicheski
	Name: Ian E. Robertson		Name: David Bronicheski
	Title:   Chief Executive Officer		Title:   Chief Financial Officer

2

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 and subsidiaries as at December 31, 2010 and 2009, and the related consolidated statements of operations, deficit, comprehensive income (loss) and accumulated other comprehensive income (loss), and cash flows for each of the years in the two-year period ended December 31, 2010. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits 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 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 financial position of the Company and subsidiaries as of December 31, 2010 and 2009 and the results of their operations and its cash flows for each of the years in the two-year period ended December 31, 2010 in conformity with Canadian generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2010, based on the criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 31, 2011 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

/s/ KPMG LLP                                

Chartered Accountants, Licensed Public Accountants

Toronto, Canada

March 31, 2011

KPMG LLP, is a Canadian limited liability partnership and a member firm of the KPMG

network of independent member firms affiliated with KPMG International Cooperative

(“KPMG International”), a Swiss entity.

KPMG Canada provides services to KPMG LLP.

3

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

INDEPENDENT AUDITORS’ REPORT

To the Shareholders of Algonquin Power & Utilities Corp.

We have audited the accompanying consolidated financial statements of Algonquin Power & Utilities Corp. and its subsidiaries, which comprise the consolidated balance sheets as at December 31, 2010 and 2009, the consolidated statements of operations, deficit, comprehensive income (loss) and accumulated other comprehensive income (loss), and cash flows for the years then ended, and notes, comprising a summary of significant accounting policies and other explanatory information.

Management’s Responsibility for the Consolidated Financial Statements

Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with Canadian generally accepted accounting principles, and for such internal control as management determines is necessary to enable the preparation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.

Auditors’ Responsibility

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

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on our judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, we consider internal control relevant to the entity’s preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements.

We believe that the audit evidence we have obtained in our audits is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the consolidated financial statements present fairly, in all material respects, the consolidated financial position of Algonquin Power & Utilities Corp. as at December 31, 2010 and 2009 and the consolidated results of its operations and its consolidated cash flows for the two years then ended in accordance with Canadian generally accepted accounting principles.

/s/ KPMG LLP                                

Chartered Accountants, Licensed Public Accountants

Toronto, Canada

March 3, 2011

KPMG LLP, is a Canadian limited liability partnership and a member firm of the KPMG

Network of independent member firms affiliated with KPMG International, a Swiss cooperative.

KPMG Canada provides services to KPMG LLP.

Algonquin Power & Utilities Corp

Consolidated Balance Sheets

(thousands of Canadian dollars)

	2010			2009
ASSETS
Current assets:
Cash	$	5,146		$	2,796
Short term investments (note 1(d))		3,674			40,010
Accounts receivable		27,082			20,484
Prepaid expenses		3,520			4,674
Income tax receivable		—			1,143
Current portion of future tax asset (note 13)		14,015			14,566
Current portion of notes receivable (note 5)		1,172			414
		54,609			84,087
Long-term investments and notes receivable (note 5)		35,902			23,470
Future non-current income tax asset (note 13)		74,006			61,219
Property, plant and equipment (note 6)		729,076			749,350
Intangible assets (note 7)		73,886			85,929
Restricted cash (note 1(e))		3,563			4,316
Deferred financing costs		258			200
Other assets (note 8)		9,617			4,842
	$	980,917		$	1,013,413
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	33,506		$	33,219
Dividends payable		5,721			1,857
Current portion of long-term liabilities (note 9)		70,490			3,360
Current portion of other long-term liabilities (note 11)		1,011			1,025
Current portion of derivative instruments (note 22)		2,338			5,775
Current income tax liability		200			5
Current portion of deferred credit (note 13)		11,020			10,500
Future income tax liability (note 13)		514			913
		124,800			56,654
Long-term liabilities (note 9)		188,641			241,412
Convertible debentures (note 10)		170,975			173,257
Other long-term liabilities (note 11)		30,872			25,228
Future non-current income tax liability (note 13)		80,953			79,914
Derivative instruments (note 22)		3,525			3,920
Deferred credit (note 13)		32,222			39,379
Shareholders’ equity:
Shareholders’ capital (notes 3 and 12)		796,576			787,037
Deficit		(347,802	)		(344,676	)
Accumulated other comprehensive loss		(99,845	)		(48,712	)
		348,929			393,649
Commitments and contigencies (note 15)
Subsequent events (notes 4(a) and 9)
	$	980,917		$	1,013,413

See accompanying notes to consolidated financial statements

5

Algonquin Power & Utilities Corp

Consolidated Statements of Operations

(thousands of Canadian dollars, except per unit amounts)

	2010			2009
Revenue:
Energy sales	$	132,726		$	130,436
Waste disposal fees		9,039			14,468
Water reclamation and distribution		37,786			38,513
Other revenue (note 20)		3,331			3,848
		182,882			187,265
Expenses
Operating		97,851			102,736
Amortization of property, plant and equipment		36,429			38,578
Amortization of intangible assets		10,144			7,305
Management costs (note 14)		—			850
Administrative expenses		14,886			10,712
Gain on foreign exchange		(528	)		(1,261	)
		158,782			158,920
Earnings before undernoted		24,100			28,345
Interest expense		25,612			21,387
Interest, dividend and other income (note 19)		(4,962	)		(6,401	)
Impairment loss of property, plant and equipment (note 6)		2,492			5,354
Write down of note receivable (note 5)		—			1,103
(Gain) / loss on derivative financial instruments (note 22)		1,103			(17,318	)
		24,245			4,125
Earnings/(loss) from operations before income taxes, non-controlling interest and corporatization costs		(145	)		24,220
Management internalization costs (note 14)		—			4,693
Other corporatization costs (note 3)		—			3,460
Earnings/(loss) before income taxes and non-controlling interest		(145	)		16,067
Income tax expense (recovery) (note 13)
Current		(69	)		397
Future		(20,159	)		(18,324	)
		(20,228	)		(17,927	)
Non-controlling interest in earnings of subsidaries		444			2,737
Net earnings	$	19,639		$	31,257
Basic net earnings per share (note 18)	$	0.21		$	0.39
Diluted net earnings per share (note 18)	$	0.21		$	0.39

See accompanying notes to consolidated financial statements

6

Algonquin Power & Utilities Corp

Consolidated Statements of Cash Flows

(thousands of Canadian dollars)

	2010			2009
Cash provided by (used in):
Operating Activities:
Net earnings	$	19,639		$	31,257
Items not affecting cash:
Amortization of property, plant and equipment		36,429			38,578
Amortization of intangible assets		10,144			7,305
Other amortization		2,911			1,441
Future income taxes / (recovery)		(20,159	)		(18,324	)
Gain on sale of land		—			(1,451	)
Stock option expense		108			—
Write down of property, plant and equipment		2,492			5,354
Write down of note receivable		—			1,103
Expense on convertible debenture conversion		—			1,252
Management internalization costs		—			4,693
Unrealized gain on derivative financial instruments		(7,142	)		(23,106	)
Minority interest		444			2,737
Unrealized foreign exchange gain		(414	)		(1,503	)
		44,452			49,336
Changes in non-cash operating working capital (note 17)		728			(1,305	)
		45,180			48,031
Financing Activities:
Cash distributions / dividends (note 16)		(18,901	)		(19,043	)
Cash distributions to non-controlling interest (notes 14 and 16)		(444	)		(809	)
Common share issue, net of costs		—			21,180
Convertible debenture issue, net of costs		—			57,975
Repayment Trustee loans		—			218
Deferred financing costs		(1,194	)		(109	)
Increase in long-term liabilities		98,787			23,000
Decrease in long-term liabilities		(80,078	)		(69,175	)
Increase / (decrease) in other long-term liabilities		4,456			(5,870	)
		2,626			7,367
Investing Activities:
Decrease in restricted cash		575			343
Decrease / (increase) in short-term investments		36,212			(39,995	)
Increase in other assets		(2,723	)		(1,597	)
Distributions received in excess of equity income		1,140			1,991
Receipt of principal on notes receivable		410			448
Proceeds from liquidation of Highground assets (note 4(f))		170			983
Proceeds from sale of land		—			2,502
Acquisition of long-term investments (notes 4(e) and 5)		(14,759	)		(87	)
Net additions to property, plant and equipment		(20,831	)		(10,916	)
The unit exchange transaction (note 3)		—			(10,813	)
Acquisitions of operating entities		(45,524	)		(1,177	)
		(45,330	)		(58,318	)
Effect of exchange rate differences on cash		(126	)		(186	)
Increase / (decrease) in cash		2,350			(3,106	)
Cash, beginning of the year		2,796			5,902
Cash, end of the year	$	5,146		$	2,796
		—			—
Supplemental disclosure of cash flow information:
Cash paid during the period for interest expense	$	21,562		$	19,956
Cash paid / (received) during the period for income taxes	$	(285	)	$	873

See accompanying notes to consolidated financial statements

7

Algonquin Power & Utilities Corp

Consolidated Statements of Deficit

(thousands of Canadian dollars)

	2010			2009
Balance, beginning of year	$	(344,676	)	$	(356,621	)
Net earnings		19,639			31,257
Distributions / dividends		(22,765	)		(19,312	)
Balance, end of year	$	(347,802	)	$	(344,676	)

See accompanying notes to consolidated financial statements

8

Algonquin Power & Utilities Corp

Consolidated Statements of Comprehensive Income / (Loss) and

Accumulated Other Comprehensive Income / (Loss)

(thousands of Canadian dollars)

	2010			2009
Net earnings	$	19,639		$	31,257
Other comprehensive income /(loss):
Forward exchange contracts settled in the year		—			(1,789	)
Translation of self sustaining foreign operations due to accounting change (note 1(n))		(37,605	)		—
Translation of self sustaining foreign operations (note 1(n))		(13,528	)		(25,481	)
Other comprehensive income / (loss)		(51,133	)		(27,270	)
Total comprehensive income / (loss)	$	(31,494	)	$	3,987
Accumulated other comprehensive loss:
Balance, beginning of the year	$	(48,712	)	$	(21,442	)
Translation of self sustaining foreign operations due to accounting change (note 1(n))		(37,605	)		—
Other comprehensive income / (loss)		(13,528	)		(27,270	)
Balance, end of the year	$	(99,845	)	$	(48,712	)

See accompanying notes to consolidated financial statements

9

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2010 and 2009

(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 and energy utilities, through investments in securities of subsidiaries including corporations, limited partnerships and trusts which carry on these businesses. The activities of the subsidiaries may be financed through equity contributions, interest bearing notes and third party project debt as described in the notes to the consolidated financial statements.

On October 27, 2009, Algonquin Power Income Fund (the “Fund”) completed a reverse take-over transaction (the “Transaction”) of Hydrogenics Corporation (“Hydrogenics”) which resulted in the Fund’s unitholders becoming shareholders in Hydrogenics which was immediately renamed Algonquin Power & Utilities Corp. As a result, the Fund itself became a wholly owned subsidiary of APUC. The transaction did not result in any change to the underlying business operations of the Fund. For accounting purposes APUC is considered a continuation of the Fund, and as such, these consolidated financial statements follow the continuity of interest method of accounting. The Transaction and its accounting treatment are more fully described in note 3.

Up to December 21, 2009, the Fund was managed by Algonquin Power Management Inc. (“APMI”) (see note 14).

On March 4, 2010 the Trustees approved a resolution changing the name of the Fund from Algonquin Power Income Fund to Algonquin Power Co. (“APCo”)

APUC’s power generation business unit conducts business under the name APCo. APCo owns or has interests in 45 renewable energy facilities and 12 thermal energy facilities representing more than 450 MW of installed electrical generation capacity. APUC’s Utility Services business unit conducts business under the name of Liberty Utilities Co (“Liberty Utilities”). Liberty Water, a wholly owned subsidiary of Liberty Utilities, owns 19 utilities in the United States of America providing water or wastewater services in the states of Arizona, Texas, Missouri and Illinois. The regulated utility operating companies are subject to regulation by the public utility commissions of the states in which they operate. The respective public utility commissions have jurisdiction with respect to rate, service, accounting procedures, issuance of securities, acquisitions and other matters. These utilities operate under cost-of-service regulation as administered by these state authorities. The utilities use a historic 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.

10

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2010 and 2009

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

1. Significant accounting policies:

(a) Basis of consolidation:

The accompanying audited consolidated financial statements of APUC have been prepared according to Canadian generally accepted accounting principles (“GAAP”), applied on a consistent basis, and includes the accounts of APUC and its wholly owned subsidiaries and variable interest entities (“VIE”) where the Company is the primary beneficiary. Long Sault is a hydroelectric generating facility in which APUC acquired its 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 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, as the Company is the primary beneficiary and therefore the Long Sault entity is subject to consolidation by the Company.

Intercompany transactions and balances have been eliminated.

(b) Accounting for rate regulated operations:

Effective October 1, 2009, APUC retrospectively adopted rate regulated accounting for Canadian GAAP reporting in its Liberty Water utilities following 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 Canadian 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. Items to which regulatory accounting requirements apply include deferred rate case costs, and capitalization of allowance for equity funds used during construction of regulated capital projects.

Deferred rate case costs relate to costs incurred by APUC’s utilities to file, prosecute and defend rate case applications and which the utility expects to receive prospective recovery through its rates approved by the regulators. Under ASC 980 these costs are capitalized and amortized over the period of rate recovery granted by the regulator while they are expensed under Canadian GAAP for non-regulated entities.

Under ASC 980, allowance for funds used during construction projects 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. It 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). Prior to the adoption of ASC 980, APUC capitalized interest costs directly attributable to the construction of these assets but did not capitalize the allowance for equity funds used during construction projects.

(c) Cash:

Cash consists of cash deposited at banks.

11

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2010 and 2009

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

1. Significant accounting policies: (continued)

(d) Short term investments:

Short term investments, consist of money market instruments with maturities in January 2011 and are recorded at cost, which approximates current market value. Included in short term investments is an investment of $3,694 (2009 - $10,000) which is denominated in US dollars.

(e) Restricted cash:

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. Amounts collected on trade accounts receivable are included in net cash provided by operating activities in the Consolidated Statements of Cash Flows. 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 current receivables aging and current payment patterns. Account balances are charged off 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) Property, plant and equipment:

Property, plant and equipment, consisting of land, facilities and equipment, are recorded at cost. The costs of acquiring or constructing facilities together with the related interest costs during the period of construction are capitalized. Interest costs capitalized for Liberty Water’s utilities also include the allowance for equity funds used during construction.

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

The facilities and equipment, which include the cost of major overhauls, are amortized on a straight-line basis over their estimated useful lives. For facilities these periods range from 15 to 40 years. Facility equipment and overhaul costs are amortized over 2 to 10 years.

In accordance with regulator-approved accounting policies, when depreciable property, plant and equipment of Liberty Water’s 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 would be charged to net earnings as incurred.

12

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2010 and 2009

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

1. Significant accounting policies: (continued)

(h) Intangible assets:

Power sales contracts and energy sales contracts acquired 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 for power sales contracts and 12 months for energy sales contracts.

Customer relationships are amortized on a straight-line basis over 40 years.

(i) Deferred costs:

Deferred costs consist of costs of arranging APCo’s credit facility.

(j) 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. Recoverability 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.

(k) Long-term investments and notes receivable:

Investments in which APUC has significant influence but not control or joint 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. All other equity investments where APUC does not have significant influence or control are accounted for under the cost method. Under the cost method of accounting, investments are carried at cost and are adjusted only for other-than-temporary declines in value and additional investments.

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 recorded at 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. The interest income on notes receivable is included in net cash provided by operating activities in the Consolidated Statements of Cash Flows.

The allowance for doubtful accounts is the Company’s best estimate of the amount of credit losses in the Company’s existing notes. The allowance is determined on an individual note basis 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. The Company does not accrue interest when a note is considered impaired. When ultimate collectability of the principal balance of the impaired note is in doubt, all cash receipts on impaired notes are applied to reduce the principal amount of such notes until the principal has been recovered and are recognized as interest income thereafter. Impairment losses are charged against the allowance and increases in the allowance are charged to bad debt expense. Notes are written off against the allowance when all possible means of collection have been exhausted and the potential for recovery is considered remote.

13

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2010 and 2009

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

1. Significant accounting policies: (continued)

(l) Other long-term liabilities:

Other long-term liabilities include advances in aid of construction. Certain of APUC’s water and wastewater utilities are provided with advances through contributions from customers, real estate developers and builders for water and sewage main extensions in order to extend water and sewer service to their properties. The amounts advanced are generally repayable over a prescribed period based on revenues generated by the housing or development in the area being developed as new customers are connected to and take service from the utilities. Generally, advances not refunded within the prescribed period are not required to be repaid. The estimated portion of the advance that will not be refunded amounts to $33,848 and is credited to property, plant and equipment as a contribution in aid of construction. APUC also receives contributions in aid of construction with no repayment requirements in which case the full amount is immediately treated as a capital grant and netted against property, plant and equipment. The estimated amount of contributions that are expected to be ultimately refunded is recorded as Advances in Aid of Construction in other long-term liabilities.

Other long-term liabilities also include deferred water rights. Deferred water rights result from 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.

Other long term liabilities also include customer deposits. Customer deposits result from the Liberty Water’s utilities’ obligation by its respective state regulator to collect a deposit from each customer of its facilities when services are connected. The deposits are refundable as allowed under the facilities’ regulatory agreement.

(m) Recognition of revenue:

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

Water reclamation and distribution revenues are recorded when processed or delivered to customers.

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 are recognized based on actual tonnage at the expected price for the contract year.

Interest from long-term investments is recorded as earned.

14

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2010 and 2009

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

1. Significant accounting policies: (continued)

(n) Foreign currency translation:

APUC’s policy for translation of foreign operations depends on whether the foreign operations are considered integrated or self-sustaining. In 2009, APUC’s foreign operations, other than Liberty Water, were considered integrated and translated into Canadian dollars using the temporal method whereby current rates of exchange are used for monetary assets and liabilities, historical rates of exchange for non-monetary assets and liabilities and average rates of exchange for revenues and expenses, except amortization which was translated at the rates of exchange applicable to the related assets. Gains and losses resulting from these translation adjustments were included in income.

As a result of the change relating to conversion of the Company from an income trust to a corporate structure at the end of 2009, the Company re-evaluated its exposure to currency exchange rate changes as determined by the underlying facts and circumstances of the economy in which the US divisions operate. The Company concluded that the US operations of the Renewable Energy and Thermal Energy divisions no longer should be classified as integrated foreign operations but rather as self-sustaining operations. Consequently, these divisions have been prospectively translated into Canadian dollars using the current rate method, effective January 1, 2010. The net exchange adjustment of $37,605 resulting from the current rate translation of non-monetary items, principally property, plant and equipment and intangible assets, as of the date of the change is included as a separate component of other comprehensive income with a corresponding reduction to the carrying amount of the non-monetary items.

Liberty Water’s utilities are considered self-sustaining foreign operations since the preponderance of operating, financing and investing transactions are denominated in U.S. dollars. These self-sustaining 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 in the Consolidated Statement of Comprehensive Income.

(o) Asset retirement obligations:

The fair value of estimated asset retirement obligations is recognized in the consolidated balance sheet when identified and a reasonable estimate of fair value can be made. The asset retirement cost, equal to the estimated fair value of the asset retirement obligation, is capitalized as part of the cost of the related long-lived asset. The asset retirement costs are depreciated over the asset’s estimated useful life and are included in amortization expense on the Consolidated Statements of Operations. 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. Actual expenditures incurred are charged against the accumulated obligation. Based on APUC’s assessments the Company does not have any significant asset retirement obligations and therefore no provision for retirement obligations have been recorded in 2010 and 2009.

15

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2010 and 2009

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

1. Significant accounting policies: (continued)

(p) Income taxes:

Income taxes are accounted for using the asset and liability method. Future 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. Future tax assets and liabilities are measured using enacted or substantively enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on future tax assets and liabilities of a change in tax rates is recognized in earnings in the year that includes the date of enactment or substantive enactment.

The structure of APUC and its subsidiaries are complex and the related tax interpretations, regulations and legislation in the tax jurisdictions in which they operate are continually changing. As a result, there are can be tax matters that have uncertain tax positions. The Company recognizes income tax benefits of uncertain tax filing positions when it is more likely than not that the ultimate determination of the tax treatment of the position will result in that benefit being realized. 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.

A valuation allowance is recorded against future tax assets to the extent that it is considered more likely than not that the future tax asset will not be realized.

(q) Financial instruments and derivatives:

APUC has classified its cash, short term investments, accounts receivable, restricted cash, accounts payable and accrued liabilities and dividends payable as held-for-trading, which are measured at fair value. Notes receivable are classified as loans and receivables, which are measured at amortized cost as there is no liquid market for these investments. Long-term liabilities, convertible debentures, and other long-term liabilities are classified as other financial liabilities, which are measured at amortized cost, using the effective interest method.

Transaction costs that are directly attributable to the acquisition or issuance of financial assets or liabilities are accounted for as part of the respective asset or liability’s carrying value at inception. Transaction costs for items classified as held-for-trading are expensed immediately. Costs considered as commitment fees paid to financial institutions are recorded in deferred costs, and amortized on a straight-line basis over the term of the debt facility.

16

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2010 and 2009

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

1. Significant accounting policies: (continued)

Financial instruments and derivatives (continued):

Unrealized holding gains and losses on trading securities are included in earnings. A decline in the market value of any held-to-maturity security below cost that is deemed to be other-than-temporary results in an impairment to reduce the carrying amount to fair value. To determine whether an impairment is other-than-temporary, the Company considers all available information relevant to the collectability of the security, including past events, current conditions, and reasonable and supportable forecasts when developing estimate of cash flows expected to be collected. Evidence considered in this assessment includes the reasons for the impairment, the severity and duration of the impairment, changes in value subsequent to year end, forecasted performance of the investee, and the general market condition in the geographic area or industry the investee operates in.

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 and the change in fair value is included in the Consolidated Statements of Operations. None of the derivatives were designated in hedging relationships for accounting purposes.

(r) Fair Value Measurements

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

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

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

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

(s) Stock Option 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 using the Black-Scholes option-pricing model.

17

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2010 and 2009

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

1. Significant accounting policies: (continued)

(t) 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 recoverability of notes receivable and long-term investments, the recoverability of future tax assets, the portion of advances in aid of construction payments that will not be repaid, assessments of asset retirement obligations, and the fair value of financial instruments, derivatives and stock options. 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.

2. Recently issued accounting pronouncements not yet adopted and accounting framework

(a) CICA Section 1582 – Business Combinations

In January 2009, the CICA issued Handbook Section 1582, Business combinations, which replaces the existing standards. This section establishes the standards for the accounting of business combinations, and states that all assets and liabilities of an acquired business will be recorded at fair value. Estimated obligations for contingent considerations and contingencies will also be recorded at fair value at the acquisition date. The standard also states that acquisition-related costs will be expensed as incurred and that restructuring charges will be expensed in the periods after the acquisition date. This standard is applied prospectively to business combinations with acquisition dates on or after January 1, 2011. Earlier adoption is permitted. The Company did not early adopt this new standard.

(b) Accounting framework

As an SEC registrant, APUC has elected to report its financial statements under US GAAP commencing with the first quarter of 2011. The change in accounting framework will be applied retrospectively to all prior periods and appropriate changes to accounting policies will be made in order to comply with US GAAP. Those US GAAP policies are expected to be consistent with the policies applied in preparing the reconciliation reflected in note 24 of these consolidated financial statements.

18

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2010 and 2009

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

3. Unit for share exchange (the “Unit Exchange Offer”)

In order to effect a change in business structure from an income trust to a corporation, on October 27, 2009, APCo’s unitholders exchanged 100% of the outstanding trust units of APCo for a new class of common shares (“New Common Shares”) of APUC (formerly Hydrogenics Corporation or Hydrogenics), on a one for one basis. Immediately prior to this exchange, under a Plan of Arrangement, Hydrogenics transferred all of its operations and substantially all its assets and liabilities to a newly created company (“New Hydrogenics”). The pre-existing publicly traded shares of Hydrogenics were contemporaneously redeemed for shares of New Hydrogenics and thus the pre-existing publicly traded shares of Hydrogenics no longer exist. As a result of the Unit Exchange Offer, APUC paid New Hydrogenics $11,307. The transaction resulted in the Unitholders of APCo indirectly holding their interest in APCo as shareholders of APUC. Excluding shares issued under the CD Exchange Offer (as defined and described below), the number of common shares of APUC outstanding immediately after completion of the Unit Exchange Offer was exactly the same as the number of APCo’s trust units outstanding immediately before the Unit Exchange Offer.

Accounting treatment of the Unit Exchange Offer

The Unit Exchange Offer is required to be accounted for as a change in business form using the continuity of interests method of accounting in accordance with Emerging Issues Committee abstract 170, “Conversion of an Unincorporated Entity to an Incorporated Entity”. Under the continuity of interests method of accounting, the transfer of the assets, liabilities and equity of APCo to APUC were recorded at their net book values as at the effective date of the Transaction. As a result, for accounting purposes, APUC is required to be accounted for as though it were a continuation of APCo but with its capital reflecting the exchange of APUC Shares for Trust Units and therefore certain terms such as shareholder/unitholder, dividend/distribution and share/unit may be used interchangeably throughout these consolidated financial statements. For the periods reported up to the effective date of the Unit Exchange Offer, all payments to unitholders were in the form of trust unit distributions, and after that date all payments to shareholders are in the form of dividends.

Comparative figures presented in the consolidated financial statements of APUC include all amounts previously reported by APCo. In addition, a future tax asset of $66,954 related to the tax attributes of Hydrogenics Corporation was recognized on the transaction date. 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 paid to New Hydrogenics was reflected as a deferred credit of $55,647 on the transaction date to be recognized in income as an income tax expense recovery as the future income tax assets are utilized. As a result of the corporatization transaction, APUC also recorded an increase to future tax liabilities. This adjustment reflects the tax impact of recording future tax assets and liabilities for temporary differences that are reversing or settling prior to 2011 which were previously not recorded since prior to the transactions these temporary difference reversals were not previously expected to be taxed in APCo.

APUC expensed corporatization costs of $3,460 during 2009 in relation to the Unit Exchange Offer.

Contemporaneously with the Unit Exchange Offer a convertible debenture exchange offer (“the CD Exchange Offer) was made by APUC to debentureholders of APCo. The CD Exchange Offer is more fully described in note 10.

19

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2010 and 2009

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

4. Acquisitions

(a) Acquisition of electrical generation and regulated distribution utility

In 2009, APUC entered into an agreement to acquire an electrical generation and regulated distribution utility in a partnership with Emera Inc. (“Emera”). APUC will own 50.001% and Emera will own 49.999% of shares of the newly formed California Pacific Utility Ventures LLC, which has agreed to acquire through its wholly owned subsidiary California Pacific Electric Company (“Calpeco”) a California-based electricity distribution utility and related generation assets (the “California Utility”). The California Utility provides electric distribution service to approximately 47,000 customers in the Lake Tahoe region.

In connection with the acquisition, on April 23, 2009 Emera also agreed to a conditional treasury subscription for approximately 8.5 million shares of APUC at a price of $3.25 per share. The proceeds of the subscription receipts are intended to fund a portion of the cost of acquisition of the California Utility.

As of December 31, 2010, APUC has incurred costs of $2,210 (2009 - $1,084) related to the acquisition of the California Utility. These costs are recorded as deferred transaction costs and are included in other assets on the Consolidated Balance Sheet.

As of December 31, 2010, APUC has incurred costs of $965 related to the transition of the California Utility. These costs are recorded as other capital assets and are included in other assets on the Consolidated Balance Sheet.

As of December 31, 2010, APUC has incurred costs of $871 related to the financing of the California Utility. These costs are recorded in other assets on the Consolidated Balance Sheet.

The acquisition of the California Utility by Calpeco closed subsequent to year end on January 1, 2011 for a purchase price of approximately US $131,790, subject to certain working capital and other closing adjustments. Delivery of the shares under the subscription receipts occurred simultaneously with the closing of the acquisition.

(b) Agreement to Acquire Electric and Gas Utilities

On December 9, 2010 APUC announced that Liberty Energy Utilities Co. (“Liberty Energy”), APUC’s utility subsidiary, had entered into agreements to acquire all issued and outstanding shares of Granite State Electric Company, a regulated electric utility, and EnergyNorth Natural Gas Inc. a regulated natural gas utility from National Grid USA (“National Grid”) for total consideration of US $285,000.

The transaction is subject to U.S. state and federal regulatory approval and is expected to close in the fall of 2011. As of December 31, 2010, APUC has incurred costs of $1,889 (2009 - $nil) related to the acquisition. These costs are recorded as deferred transaction costs and are included in other assets on the Consolidated Balance Sheet.

In connection with these acquisitions, Emera has agreed to a treasury subscription of subscription receipts convertible into 12.0 million APUC common shares upon closing of the transactions at a purchase price of $5.00 per share. The issuance of these subscription receipts is subject to regulatory approval.

20

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2010 and 2009

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

4. Acquisitions (continued)

(c) Acquisition of Hydroelectric Generation Assets (“Tinker Acquisition”)

On January 12, 2010, APUC acquired certain electrical generating facility assets located in New Brunswick and Maine. The acquisition consisted of three hydroelectric generating stations, most notably the 34.5MW Tinker Hydroelectric station located on the Aroostook River near the Town of Perth-Andover, New Brunswick. The acquisition also included five thermal generating stations and certain regulated New Brunswick Independent System Operator transmission lines located in proximity to the generating facilities. In connection with the Tinker Acquisition, on February 4, 2010, APUC also acquired a related energy services business (“Energy Services Business”).The Energy Services Business retails the electricity generated by the Tinker facilities to commercial and industrial customers in northern Maine.

The total purchase price, including acquisition costs, was $40,671. Acquisition costs of $390 were paid in 2009 which were recorded as deferred transaction costs and included in other assets on the consolidated balance sheet at December 31, 2009 and included in acquisition costs in 2010.

The acquisition has been accounted for using the purchase method, with earnings from operations included since the date of acquisition.

The consideration paid by APUC has been preliminarily allocated to net assets acquired as follows:

Working capital (net of cash received of $1)	$	69
Property, plant and equipment		40,817
Intangible asset – energy sales contracts		4,421
Non-current future income tax liability		(1,262	)
Derivative liability – energy forward purchase contracts (note 22)		(3,374	)
Total cash consideration	$	40,671

The allocation of the purchase price has been based upon the fair values of the assets and liabilities as of the date of acquisition.

21

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2010 and 2009

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

4. Acquisitions (continued)

(d) Acquisition of Water Utility System (“the Galveston Utility”)

On March 17, 2010 Liberty Water, a wholly owned subsidiary of APUC, acquired water distribution and wastewater collection system located near Galveston, Texas for a total purchase price of $2,038. The Galveston Utility provides water distribution and wastewater collection services to approximately 260 equivalent residential connections.

The acquisition has been accounted for using the purchase method, with earnings from operations included since the date of acquisition.

The consideration paid by APUC has been allocated to net assets acquired as follows:

Property, plant and equipment	$	2,023
Intangible asset		15
Total cash consideration	$	2,038

(e) Acquisition of Entrada Del Oro Sewer Company

In 2008, the Company entered into an agreement to acquire the shares of Entrada Del Oro Sewer Company located in Arizona, for $707 (US$670).

In accordance with the purchase and sale agreement, APUC is required to make additional payments to the previous owners for each additional customer connected to the utility. These payments continue until 2018. As of December 31, 2010, APUC has paid $83 (U.S. $80) (2009 - $87 (U.S. $78)) as a growth premium, and increased long term investments and notes receivable by a similar amount.

22

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2010 and 2009

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

4. Acquisitions (continued)

(f) Highground Capital Corporation

In 2008, the Company entered into an agreement with Highground Capital Corporation (“Highground”), CJIG Management Inc. (“CJIG”), which is the manager of Highground and a related party of the Company controlled by the shareholders of Algonquin Power Management Inc (“APMI”) who are current or former executives of the Company. Under the agreement, CJIG acquired all of the issued and outstanding common shares of Highground and the Company issued trust units to the Highground shareholders and CJIG.

The Company initially recorded the trust units issued at their fair value of $7.69 per unit which, net of transaction costs of $767, resulted in proceeds of the trust units being initially recorded at a value of $26,203. By December 31, 2010, the Company has received consideration and issued equity as follows:

Consideration received:
Cash and assets received prior to December 31 2008	$	26,203
Cash received in 2009		983
Cash received in 2010		170
	$	27,356

In 2009, APUC’s consideration received from the acquisition exceeded $26,970, the minimum contemplated under the agreements, and, as a result APUC is entitled to 50% of any additional proceeds from the assets formerly owned by Highground. CJIG is entitled to the remaining 50% of any proceeds in excess of the minimum amount. During 2010, APUC received $170 (2009 - $983) from CJIG as APUC’s share of the 50% of additional proceeds from the further liquidation of the assets held by Highground. This has been recorded as an increased amount assigned to the equity originally issued.

The remaining investments, formerly held by Highground, currently consist of two non-liquid debt assets having an approximate principal amount of $2,227. APUC’s 50% share of any additional proceeds from liquidation of the remaining Highground assets will be recorded as additional proceeds when received from CJIG.

23

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2010 and 2009

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

5. Long-term investments and notes receivable

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

	2010			2009
32.4% of Class B non-voting shares of Kirkland Lake Power Corp.	$	8,197		$	8,344
25% of Class B non-voting shares of Cochrane Power Corporation		5,775			6,544
45% partnership interest in the Algonquin Power (Rattle Brook) Partnership		3,790			3,827
Investment in Entrada Del Oro (note 4 (e))		568			709
Red Lily Subordinated loan, interest at 12.5% (note 5 (a))		6,565
Red Lily Senior loan, interest at 6.31% (note 5 (a))		6,100			—
Chapais Énergie, Société en Commandite 12.1% interest in Tranche A and Tranche B term loans The loans bear interest at the rate of 10.789% and 4.91%, respectively		3,329			3,701
Silverleaf resorts loan, interest at 15.48% (note 5 (b))		2,010			—
Note Receivable - Twin Falls. The note bears interest at the rate of 6.75%		740			759
		37,074			23,884
Less: current portion		(1,172	)		(414	)
Total long term investments and notes receivable	$	35,902		$	23,470

The above notes are secured by the underlying assets of the respective facilities. There is no allowance for doubtful account in regards to the notes receivable as at December 31, 2010 and 2009.

(a) Red Lily I

On April 19, 2010, the Company entered into agreements to provide development, construction, operation and supervision services related to the construction, commissioning and operation of a 26.4 megawatt wind energy facility (“Red Lily I”) in south-eastern Saskatchewan.

The equity in Red Lily I (‘the Partnership”) is owned by an independent investor. The Company’s investment in Red Lily I is in the form of participation in a portion of the senior debt facility, and a subordinated debt facility to the Partnership. APUC’s commitment under the senior debt facility is to advance up to $13,000 of the Tranche 2 senior debt. The third party lender has also committed to provide $31,000 of senior debt to the Partnership. The senior debt will earn an interest rate of 6.31% and will mature five years following commissioning of the project. The subordinated debt will earn an interest rate of 12.5%. The senior debt is secured by substantially all the assets of the Partnership.

24

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2010 and 2009

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

5. Long-term investments and notes receivable (continued)

(a) Red Lily I (continued)

In 2010, APUC funded $6,100 of senior debt to the project (2009 - $nil) and $6,565 in subordinated debt to the Partnership.

A second tranche of subordinated debt for an amount equal to the amounts outstanding on Tranche 2 of the senior debt but no greater than $17,000 will be advanced five years following commissioning of the project. 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. The subordinated debt earns an interest rate of 12.5%, the principal matures 25 years following commissioning of the project but is repayable by Red Lily in whole or in part at any time after five years, without a pre-payment premium. The subordinated debt is secured by substantially all the assets of the Partnership but is subordinated to the senior lenders debt.

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 debt of up to $19,500, exercisable for a period of 90 days commencing five years from the date of commissioning of the project.

(b) Silverleaf Resorts Inc – Hill County

On July 29, 2010, Liberty Water, a wholly owned subsidiary of APUC, made an investment in its Hill Country facility, a part of Silverleaf Resorts Inc.’s (“SRI”) facilities in Comal County, Texas. The investment of $2,094 (U.S. $2,021) was made under an agreement with SRI to increase the capacity of a wastewater treatment facility to support the growth of the utility. This investment has been recorded in property, plant and equipment as additional capacity conveyed by SRI together with note receivable for funds advanced by APUC.

The note has a 10 year term and bears interest at 15.48%. The note is repayable in cash to the extent expansion does not form part of the rate base of the utility during the 10 year term. To the extent that the cost of the expansion becomes part of the rate base of the utility, the note will be assigned as payment to Silverleaf for the expansion costs with the excess received in cash.

(c) Land Fill Gas

In 2009, APUC wrote off the remaining $1,103 (U.S. - $999) principal balance of the note receivable related to its land fill gas facility which was previously recorded in other long term investments.

25

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2010 and 2009

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

6. Property, plant and equipment

Property, plant and equipment consist of the following:

2010
	Cost		Accumulated amortization		Net book value
Land	$	11,709	$	—	$	11,709
Facilities		921,032		231,098		689,934
Equipment		48,747		21,314		27,433
	$	981,488	$	252,412	$	729,076
2009
	Cost		Accumulated amortization		Net book value
Land	$	11,323	$	—	$	11,323
Facilities		953,826		224,244		729,582
Equipment		30,325		21,880		8,445
	$	995,474	$	246,124	$	749,350

Facilities include cost of $94,606 (2009 - $94,606) and accumulated amortization of $27,962 (2009 - $25,426) related to facilities under capital lease or owned by consolidated variable interest entities, and $10,542 (2009 - $11,551) of construction in process. Amortization expense of facilities under capital lease was $2,536 (2009 - $2,537). In addition $3,731 (2009—$5,926) of contributions received in aid of construction have been credited to facilities cost. Equipment includes cost of $4,402 (2009 - $4,096) and accumulated amortization of $2,149 (2009 - $1,857) related to equipment under capital lease. Amortization expense of equipment under capital lease was $292 (2009 - $302). In 2010, interest of $nil (2009 - $nil) was capitalized to facilities within property, plant and equipment.

In December 2010, APCo wrote down its investment in three small hydro facilities and recognized an impairment charge on property, plant and equipment of $1,836 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 2010, the equipment at the Crossroads thermal facility in New Jersey met the conditions for asset held for sale. The equipment was sold subsequent to December 31, 2010. The carrying value was written down to its fair value less cost to sell resulting in a loss of $656, which was included in earnings for the period. The fair value of the equipment was based on the sales price.

In December 2009, APCo decided to dispose of its investments in its last remaining Landfill Gas assets and its biomass joint venture Drayton Valley Power. APCo therefore tested these investments for recoverability using a net realizeable value valuation technique. As a result, APCo determined that these assets were impaired as at December 31, 2009 and recognized an impairment charge on property, plant and equipment of $5,354 representing the difference between the carrying value of the assets and their net fair value. In 2009 APCo also recorded $500 related to costs associated with decommissioning the land fill gas facilities and recorded this on the Statement of Operations with a corresponding increase in other long term liabilities.

26

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2010 and 2009

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

7. Intangible assets

Intangible assets consist of the following:

2010
	Cost		Accumulated amortization		Net book value
Power sales contracts	$	102,980	$	45,345	$	57,635
Customer relationships		18,811		2,912		15,899
Energy sales contract		4,228		3,876		352
Licenses and agreements		683		683		—
	$	126,702	$	52,816	$	73,886
2009
	Cost		Accumulated amortization		Net book value
Power sales contracts	$	119,533	$	51,333	$	68,200
Customer relationships		20,279		2,564		17,715
Licenses and agreements		696		682		14
	$	140,508	$	54,579	$	85,929

Estimated amortization expense for intangibles for the next five years is: $6,526 in 2011, $6,120 in 2012, $6,117 in 2013, $6,070 in 2014, and $6,070 in 2015.

8. Other Assets

Other assets consist of the following:

	2010		2009
Regulatory assets	$	2,164	$	1,713
California Utility – deferred financing		871		—
California Utility – other capital assets		965		—
Wind development assets		788		788
Deferred transaction costs -
California Utility (note 4(a) )		2,210		1,084
Tinker acquisition (note 4 (c))		—		390
Energy North and Granite State acquisition (note 4(b))		1,888		—
Other		731		867
	$	9,617	$	4,842

Regulatory assets are amortized over the period of rate recovery granted by the regulator.

27

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2010 and 2009

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

9. Long-term liabilities

Long term liabilities consist of the following:

	2010		2009
Senior Secured Revolving Credit Facility: Revolving line of credit interest rate is equal to bankers acceptance or LIBOR plus 0.95%. The effective rate of interest for 2010 was 2.13% (2009 – 1.71%).	$	64,500	$	94,000
AirSource Senior Debt Financing: Interest rate is equal to bankers’ acceptance plus 1% and matures on October 31, 2011. Monthly interest and quarterly principal payments totaling $1,741 (2009—$1,649). The effective rate of interest for 2010 was 1.81% (2009 – 1.78%).		68,789		70,271
Liberty Water Senior Unsecured: U.S. $50,000 senior unsecured note, interest rate of 5.6% matures December 22, 2020. The note is 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.		48,876		—
Senior Debt Long Sault Rapids: Interest at rate of 10.2% repayable in blended monthly installments of $402 and maturing December, 2027.		39,870		40,594
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, 2020. The variable interest rate is determined by the remarketing agent. The effective interest rate for 2010 is 1.33% (2009 – 1.44%).		19,096		20,179
Litchfield Park Service Company Bonds: 1999 and 2001 IDA Bonds. Interest rates of 5.87% and 6.71% repayable in blended semi-annual installments maturing October 2023 and October 2031. Principal payments of U.S. $270 (2009 – U.S. $240). The balance of these notes at December 31, 2010 was U.S. $4,112 and U.S. $7,884, respectively (2009 – U.S. $4,325 and U.S. $7,983).		11,931		12,936
Senior Debt Chute Ford: Interest rate of 11.6% repayable in monthly interest and principal installments of $64 and maturing April, 2020.		4,336		4,580

28

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2010 and 2009

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

9. Long term liabilities (continued)

	2010			2009
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, 2020 and December, 2017. The balance of these notes at December 31, 2010 was US$1,384 and US$95 respectively (2009 – US$1,478 and US$102).		1,489			1,707
Bonds Payable: Obligation to the City of Sanger due October 1, 2011 at interest rates varying from 5.45% to 5.55%. U.S. $230 (2009 - U.S. $445).		229			468
Other		15			37
	$	259,131		$	244,772
Less: current portion		(70,490	)		(3,360	)
	$	188,641		$	241,412

Subsequent to year end, APCo renewed its senior secured revolving credit facility in the amount of $142,000 (the “Facility”) for a three year term with its Canadian bank syndicate. The Facility now has a maturity date of February 14, 2014.

At December 31, 2010, $64,500 (2009 - $94,000) has been drawn on the Facility. In addition, the availability of the revolving credit facility has been reduced for certain outstanding letters of credit in amounts totaling $33,122 (2009 - $33,108). Therefore, APCo had $44,400 of undrawn committed and available bank facilities as at December 31, 2010.

The terms of the Facility contain certain financial covenants including debt service ratios and various leverage ratios which can limit the amounts available for borrowing. Based on current covenants at December 31, 2010, APCo is able to access the entire amount of the Facility. The facility is secured by a fixed and floating charge over all APCo entities.

On December 22, 2010 APUC completed a $50,000 private placement debt financing commitment for its subsidiary, Liberty Water Co. (“Liberty Water”). The notes are senior unsecured with a ten year maturity date of December 2020 and bears interest at 5.6%. The notes are interest only, payable semi-annually, until June 20, 2016 with semi-annual interest payments and annual principal repayments of U.S. $5,000 thereafter. As of December 31, 2010, Liberty Water incurred deferred financing costs of $854 which is amortized to interest expense over the term of the loan using the effective interest rate method.

29

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2010 and 2009

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

9. Long term liabilities (continued)

Total long term debt is reported net of deferred financing costs. Certain of our long-term debt has been issued at a subsidiary level relating to a specific operating facility and is secured by the respective facility with no other recourse to APUC or APCo. 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 APCo and APUC from specific facilities. As at December 31, 2010 APUC and its subsidiaries were in compliance with all debt covenants.

Interest paid on the long-term liabilities was $9,064 (2009 - $9,446).

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

2011	$	70,490
2012		1,543
2013		1,695
2014		66,354
2015		2,041
Thereafter		117,008
	$	259,131

The AirSource senior debt matures in October, 2011. As of December 31, 2010, the outstanding amount due has been recorded within the current portion of the long-term liabilities on the Consolidated Balance Sheet.

10. Convertible Debentures

Contemporaneously with the Unit Exchange Offer, on October 27, 2009 (see note 3), holders of APCo’s convertible debentures exchanged their convertible debentures for convertible debentures of APUC (the “New Debentures”) or for New Common Shares of APUC resulting in APCo’s debentureholders becoming debentureholders or shareholders of APUC.

Pursuant to the CD Exchange Offer, $63,755 of the outstanding Series 1 debentures of APCo were exchanged for new Series 1 convertible unsecured subordinated debentures of APUC in a principal amount of $66,943, and $21,209 of the current Series 1 debentures of APCo were exchanged for 6,607,027 shares of APUC. In addition, all of the outstanding Series 2 convertible debentures of APCo were exchanged for New Series 2 convertible unsecured subordinated debentures of APUC in a principal amount of $59,967.

Accounting treatment of the CD Exchange Offer

The terms of the CD Exchange Offer are considered a modification of the terms of the existing debentures of APCo rather than an extinguishment since the present value of the cash flows of the liability component of both the New Series 1 and New Series 2 debentures did not change by more than 10% as compared to the terms of the original debentures exchanged. Accordingly, the consolidated balance sheet reflects the convertible debentures at their original carrying values, net of transaction costs associated with the CD Exchange Offer. These transaction costs are recorded as deferred costs and are amortized to interest expense over the remaining terms of the convertible debentures using the effective interest rate method.

30

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2010 and 2009

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

10. Convertible Debentures (continued):

Under the terms of the CD Exchange Offer, the New Series 1 convertible debentures of APUC were issued at a face value of 105% of the principle amount of the original Series 1 debentures of APCo. The change in conversion price of the New Series 1 convertible debentures under the CD Exchange Offer resulted in the fair value of the conversion feature increasing by $1,179 as compared to the original Series 1 debentures. The change in conversion price of the New Series 2 convertible debentures under the CD Exchange Offer resulted in the fair value of the conversion feature decreasing from the original Series 2 convertible debentures carrying value of $479 to $308. The changes of $1,179 and $171 in the fair value of the conversion features on the Series 1 and Series 2 debentures are recorded as a change in the discount on debt, with an offsetting adjustment to equity. The discounts on debt are treated as additional debt issuance costs which are amortized to interest expense over the remaining terms of the convertible debentures using the effective interest rate method.

In addition, an element of the CD Exchange Offer to the Series 1 convertible debenture holders was an option to convert a portion of Series 1 convertible debentures to equity at a rate of 311.52 APUC Shares for each $1 principal amount of Series 1 convertible debentures. This resulted in an accounting debt settlement expense of $1,252 which is included in corporatization costs on the consolidated statement of operations. The CD Exchange Offer resulted in the holders of the Series 1 convertible debentures converting $21,209 of the outstanding principal balance of Series 1 convertible debentures into 6,607,027 common shares of APUC.

The pro rata portion of existing deferred financing charges associated with the Series 1 convertible debentures of $306 is recorded in the amount recorded for the common shares issued on conversion. In addition, a proportionate allocation of the total deferred transaction costs associated with the CD Exchange Offer is recorded as part of the issuance costs of the new APUC shares. APUC incurred transaction costs of $1,453 related to the CD Exchange Offer for the Series 1 convertible debentures of which $1,090 is allocated to the convertible debentures as debt issuance costs and $363 has been allocated to issuance costs related to the new APUC shares. APUC also incurred costs of $1,453 related to the CD Exchange Offer for the Series 2 convertible debentures which has been allocated to the convertible debentures as debt issuance costs.

The exchange of $63,755 of Series 1 convertible debentures that were not converted to shares, after adjustment for the 5% premium included in the CD Exchange Offer, resulted in an increase in the principal balance of the new Series 1 convertible debentures to $66,943. The increase of $3,188 is accounted for as additional debt issuance costs and is amortized to interest expense over the term of the new convertible debentures using the effective interest rate method.

31

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2010 and 2009

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

10. Convertible Debentures (continued):

On December 2, 2009, APUC issued 63,250 convertible unsecured subordinated debentures (Series 3) at a price of $1 per debenture for gross proceeds of $63,250 and net proceeds of $60,518. The debentures are due June 30, 2017 and bear interest at 7.00% per annum, payable semi-annually in arrears on June 30 and December 31 each year. The convertible debentures are convertible into common shares of APUC at the option of the holder at a conversion price of $4.20 per common share, being a ratio of approximately 238.1 common shares per $1 principal amount of debentures. The debentures cannot be redeemed by APUC on or before December 31, 2012. APUC performed an evaluation of the embedded conversion option and determined that its value was $4,275 and as a result this portion of the debenture is classified as equity with the remaining amount classified as a liability. The liability component of the convertible debentures increases to their face value over the term of the debentures and the offsetting charge to earnings is classified as interest expense on the consolidated statements of operations.

Total interest paid on the convertible debentures in 2010 was $13,053 (2009 - $9,696).

32

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2010 and 2009

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

10. Convertible Debentures (continued):

2010	New Series 1			New Series 2			Series 3			Total
Maturity date		2014 November 30			2016 November 30			2017 June 30
Interest rate		7.50	%		6.35	%		7.00	%
Conversion price per share	$	4.08		$	6.00		$	4.20
Carrying value at December 31, 2009		60,728			56,241			56,288			173,257
Conversion to shares (Note12), net of costs		(4,094	)		—			(311	)		(4,405	)
Amortization and accretion		1,000			425			698			2,123
Carrying value at December 31, 2010	$	57,634		$	56,666		$	56,675		$	170,975
Face value at December 31, 2010	$	62,470		$	59,967		$	62,905		$	185,342

2009	New Series 1			New Series 2			Series 3			Total
Maturity date		2014 November 30			2016 November 30			2017 June 30
Interest rate		7.50	%		6.35	%		7.00	%
Conversion price per share	$	4.08		$	6.00		$	4.20
Carrying value at December 31, 2008		83,178			57,249			—			140,427
Issued pursuant to December 2, 2009 offering		—			—			63,250			63,250
Change in equity component		(1,179	)		171			(4,275	)		(5,283	)
Conversion to shares (Note12), net of costs		(21,209	)		(33	)		—			(21,242	)
Deferred issue costs		(784	)		(1,453	)		(2,731	)		(4,968	)
Amortization and accretion		722			307			44			1,073
Carrying value at December 31, 2009	$	60,728		$	56,241		$	56,288		$	173,257
Face value at December 31, 2009	$	66,943		$	59,967		$	63,250		$	190,160

33

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2010 and 2009

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

11. Other long-term liabilities

Other long term liabilities consist of the following:

	2010			2009
Advances in aid of construction (note 1(l))	$	21,267		$	14,952
Deferred water rights inducement		3,008			3,089
Customer deposits		1,985			2,405
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		524			456
Other		5,099			5,351
		31,883			26,253
Less: current portion		(1,011	)		(1,025	)
	$	30,872		$	25,228

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

2010	$	1,011
2011		165
2012		78
2013		68
2014		—
Thereafter		30,561
	$	31,883

Interest paid on other long-term liabilities was $29 (2009 - $37).

34

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2010 and 2009

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

12. Shareholders’ equity/Unitholders’ equity

Number of common shares/trust units:

	2010		2009
Common shares / Trust units, beginning of period		93,064,120		77,574,372
Issued on conversion of Algonquin (AirSource) Power LP exchangeable units		—		2,005,721
Conversion of convertible debentures (Note 11)		1,178,478		6,607,027
Issued pursuant to management internalization		1,180,180		—
Issued pursuant to offering		—		6,877,000
Common shares, end of period		95,422,778		93,064,120

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 outstanding.

On October 27, 2009, pursuant to the Unit Exchange Offer (see note 3), APCo’s unitholders exchanged 100% of the outstanding trust units of APCo for a new class of common shares (“New Common Shares”) of APUC on a one for one basis. As a result, the existing unitholders of APCo became shareholders of APUC and APCo became a subsidiary of APUC.

On December 2, 2009, APUC issued 6,877,000 common shares at $3.35 per common share for gross proceeds of $23,038 before issuance costs of $1,495, ($1,002 net of tax) for net proceeds of $21,533.

On June 29, 2010, the Company issued 1,180,180 shares valued at $4,763 pursuant to the Management Internalization Agreement signed on December 21, 2009 (note 16). The issuance of shares and final settlement was approved by the Company’s shareholders at its annual general meeting held on June 23, 2010.

In 2010, $4,473 principal amount of New Series 1 Debentures were converted at the option of the holders at a price of $4.08 for each share into 1,096,335 shares of APUC. The carrying amount of these debentures net of unamortized issuance costs and the bifurcated equity component totaling $4,094 has been recorded as share capital.

In 2010, $345 principal amount of Series 3 Debentures were converted at the option of the holders at a price of $4.20 for each share into 82,142 shares of APUC. The carrying amount of these debentures net of unamortized issuance costs and the bifurcated equity component totaling $311 has been recorded as share capital.

35

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2010 and 2009

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

12. Shareholders’ equity/Unitholders’ equity (continued):

At a special meeting of Exchangeable Unitholders of Algonquin (AirSource) Power LP in December 2009, amendments were approved to amend the agreements related to the Exchangeable Units to allow the exchange of Exchangeable Units for common shares of APUC, as opposed to units of APCo, and to change the definition of “Redemption Date” as set out in the Partnership Agreement. As a result of these changes, APUC exercised the compulsory acquisition provisions of the Exchangeable Units on December 31, 2009 and all of the remaining outstanding Exchangeable Units were exchanged for 532,074 common shares of APUC, as per the formula set out in the original agreements. As a result, there are no outstanding Exchangeable Units after January 1, 2010 and consequently the non-controlling interest balance at December 31, 2010 is reduced to $nil (2009 - $nil). At December 31, 2010 no amount was included in non-controlling interest (2009 - $1,928) in the statement of operations for the allocation of earnings to the exchangeable unitholders (AirSource Power LP).

Shareholders equity/Unitholders’ Equity consists of the following:

	2010		2009
Balance of Common shares/Trust Units, beginning of period	$	781,274	$	721,953
Issued on conversion of Airsource exchangeable units		—		14,487
Conversion of convertible debentures, net of costs		4,621		21,825
Common Share issue, net of costs		—		22,026
Common shares issued pursuant to management internalization (Note 14)		4,763		—
Proceeds from liquidation of Highground assets (Note 4(f))		170		983
Balance of Shares, end of the period	$	790,828	$	781,274
Contributed surplus – stock options		108		—
Equity component of convertible debentures (Note 10)		5,640		5,763
Shareholders’ equity, end of period	$	796,576	$	787,037

36

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2010 and 2009

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

12. Shareholders’ capital (continued)

Stock Option Plan

On June 23, 2010, the Company’s shareholders approved a stock option plan (the “Plan”) that 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. Optionholders 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 a 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.

On August 12, 2010, the Board approved the grant of 1,102,041 options to senior executives of the Company. The options allow for the purchase of common shares at a price of $4.05, the market price of the underlying common share at the date of grant. One-third of the options vest on each of January 1, 2011, 2012 and 2013. Options may be exercised up to eight years following the date of grant.

The Company determines the fair value of options granted using the Black-Scholes option-pricing model. The following assumptions were used in determining the fair value of share options granted:

	2010
Risk-free Interest		2.9	%
Expected Volatility		29.2	%
Expected dividend yield		5.9	%
Expected Life		8 years
Grant date fair value per option	$	0.61

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 rates in dividends of our shares.

37

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2010 and 2009

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

12. Shareholders’ capital (continued)

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. At December 31, 2010, APUC recorded $108 (2009 - $nil) in compensation expense. As at December 31, 2010, there was $562 (2009 - $nil) of total unrecognized compensation costs related to non-vested options granted under the Plan. The cost is expected to be recognized over a period of 1.9 years.

No share options were exercised in 2010 or exercisable at December 31, 2010. The intrinsic value of the 1,102,041 non-vested shares as at December 31, 2010 was $1,069 (2009- $nil).

Shareholders’ Rights Plan

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.

38

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2010 and 2009

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

13. 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 31% (2009 - 33%). The differences are as follows:

	2010			2009
Expected income tax expense / (recovery) at Canadian statutory rate	$	(45	)	$	5,302
Increase (decrease) resulting from:
Accounting losses (income) of APCo taxed at the unitholder level		—			(20,790	)
Recognition of deferred credit		(6,636	)		—
Differences in tax rates in subsidiaries and changes in tax rates		(203	)		(1,848	)
Change in valuation allowances		(7,486	)		10,688
Foreign exchange loss on intercompany items (US)		(6,228	)		(13,464	)
Non deductible expenses and other		370			2,185
Income tax recovery	$	(20,228	)	$	(17,927	)

The Unit Exchange Offer (Note 3), together with changes in tax rates enacted in December 2009, resulted in APUC recognizing a future income tax asset of $60,014 and a deferred credit in relation to this asset of $49,879 as at December 31, 2009. The deferred credit is being recorded to reduce income tax expense in proportion to the net reduction in the future income tax asset that gave rise to the deferred credit. Current and future income taxes have been provided in respect of taxable income and temporary differences related to the Company and its subsidiaries.

For the years ended December 31, 2010 and 2009, income/(loss) before taxes consists of the following:

	2010			2009
Canadian operations	$	(4,152	)	$	7,284
U.S. operations		4,007			8,783
	$	(145	)	$	16,067

39

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2010 and 2009

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

13. Income taxes (continued)

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

	Current			Deferred			Total
Year ended December 31, 2010
Canada	$	200		$	(518	)	$	(318	)
United States		(269	)		(19,641	)		(19,910	)
	$	(69	)	$	(20,159	)	$	(20,228	)
Year ended December 31, 2009
Canada	$	313		$	4,481		$	4,794
United States		84			(22,805	)		(22,721	)
	$	397		$	(18,324	)	$	(17,927	)

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 future tax assets and future tax liabilities at December 31, 2010 and 2009 are presented below:

	2010			2009
Future tax assets:
Non-capital losses, investment tax credits, currently non-deductible interest expense and financing costs	$	115,472		$	104,455
Unrealized foreign exchange differences on intercompany notes		17,860			25,138
Customer advances in aid of construction		5,559			5,393
Foreign exchange hedges and interest rate swaps		1,459			2,865
Total future tax assets		140,350			137,851
Less: Valuation allowance		(27,907	)		(35,393	)
Total future tax assets		112,443			102,458
Future tax liabilities:
Property, plant and equipment		(96,554	)		(96,960	)
Intangible assets		(7,639	)		(8,409	)
Other		(1,696	)		(2,131	)
Total future tax liabilities		(105,889	)		(107,500	)
Net future tax asset / (liability)	$	6,554		$	(5,042	)

The valuation allowance for future tax assets as of December 31, 2010 and 2009 was $27,907 and $35,393, respectively. The net change in the total valuation allowance was a decrease of $7,486 in 2010 and an increase of $10,688 in 2009. The valuation allowance at December 31, 2010 was primarily related to operating losses and foreign exchange losses on the intercompany debts that, in the judgment of management, are not more likely than not to be realized. In assessing the realizability of future tax assets, management considers whether it is more likely than not that some portion or all of the future tax assets will not be realized. The ultimate realization of future 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 future tax liabilities (including the impact of available carryback and carryforward periods), projected future taxable income, and tax-planning strategies in making this assessment.

40

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2010 and 2009

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

13. Income taxes (continued)

Future income taxes are classified in the financial statements as:

	2010			2009
Future current income tax asset	$	14,015		$	14,566
Future non-current income tax asset Future current income tax liability		74,006 (514	)		61,219 (913	)
Future non-current income tax liability		(80,953	)		(79,914	)
	$	6,554		$	(5,042	)

As at December 31, 2010, the Company had non capital loss carryforwards available to reduce future years taxable income, which expire as follows:

Year of expiry	Non-capital loss carryforward
2014	$	29,023
2015		33,957
2019		135,095
2020 and onwards		69,604
	$	267,679

41

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2010 and 2009

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

14. Related party transactions

On December 21, 2009, the Board of Directors of APUC (the “Board”) reached an agreement with APMI to internalize all management functions of the APCo which were provided by APMI. APUC acquired APMI’s interest in the management services agreement, with consideration paid in the form of issuance of 1,158,748 APUC shares (the “Shares”). For accounting purposes, the expense has been measured at $4,693 using a price for each share of $4.03, the adjusted closing market price on December 21 2009, the date the agreement was ratified.

Up to December 21, 2009, APMI provided management services including advice and consultation concerning business planning, support, guidance and policy making and general management services. In 2009, APMI was paid on a cost recovery basis for all costs incurred and charged $850. APMI was also entitled to an incentive fee of 25% on all distributable cash (as defined in the management agreement) generated in excess of $0.92 per trust unit.

APUC has leased its head office facilities since 2001 from an entity owned by the shareholders of APMI on a net basis. Base lease costs for 2010 were $327 (2009 - $331).

APUC utilizes chartered aircraft, including the use of an aircraft owned by an affiliate of APMI, Algonquin Airlink Inc. In 2004, APUC entered into an agreement and remitted $1,300 to the affiliate as an advance against expense reimbursements (including engine utilization reserves) for APUC’s business use of the aircraft. Under the terms of this arrangement, APUC will have priority access to make use of the aircraft for a specified number of hours at a cost equal solely to the third party direct operating costs incurred when flying the aircraft. During the year, APUC incurred costs in connection with the use of the aircraft of $430 (2009 - $367) and amortization expense related to the advance against expense reimbursements of $112 (2009 - $153). At December 31, 2010, the remaining amount of the advance was $554 (2009 - $666) and is recorded in other assets.

Affiliates of APMI hold 60% of the outstanding Class B limited partnership units issued by the St. Leon Wind Energy LP (“St. Leon LP”), an indirect subsidiary of APUC and the legal owner of the St. Leon facility. The holders of the Class B Units are entitled to 2.5% of the income allocations and cash distributions from St. Leon LP for a 5 year period commencing June 17, 2008 growing to a maximum of 10% by year 15. In any particular period, cash distributions to the holders of the Class B Units are only to be made after distributions have been made to the other partners, in an aggregate amount, equal to the debt service on the outstanding debt in respect of such period. The related holders of the Class B units are entitled to cash distributions of $266 for the year ended December 31, 2010 (2009 - $292).

Pursuant to the agreement entered into on June 27, 2008 between the Company, Highground and CJIG (Note 4(f)), APMI was entitled to a fee of approximately $240 from the Company. This fee was paid in 2009.

42

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2010 and 2009

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

14. Related party transactions (continued)

During 2007, Algonquin allowed its offer to acquire Clean Power Income Fund to expire and earned a termination fee of $1,800 of which APUC agreed to pay APMI $105. This amount has been accrued and included in accounts payable on the consolidated balance sheet.

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. The royalty fee is initially equal to 0.75% of gross energy revenue, increasing every five years up to 2% after twenty-five years. APUC has agreed to acquire APMI’s interest in this royalty for an amount of $600. APMI is also entitled to a development fee of up to $400 following commercial operation of the project and has agreed to permit the Board to determine the portion of such fee which will be paid following commercial operation of the facility. APUC received and recognized $210 in other revenue related to this fee in the twelve months ended December 31, 2010.

APUC has operation and maintenance service agreements with three hydroelectric generating facilities owned by affiliates of APMI. As a result of these agreements, APUC employees operate these hydroelectric generating facilities owned by affiliates of APMI. These facilities are charged on a cost recovery basis for time and material incurred at these sites.

Under these arrangements, as at December 31, 2010 amount due from the above related party transactions was $718 (December 31, 2009 - $1,028) and amounts due to related parties was $901 (December 31, 2009 - $827).

A member of the Board of Directors of APUC is an executive at Emera Inc (“Emera”). A contract with a subsidiary of Emera to purchase energy on Independent System Operator New England (“ISO NE”) and provide scheduling services on ISO NE was included as part of the acquisition of the Energy Services Business associated with the Tinker Acquisition. The contract expired March 31, 2010 and was not renewed. As a result of this contract, during 2010 a subsidiary of Emera provided services to and purchased energy on ISO NE on behalf of the Energy Services Business. In this capacity, APUC paid a subsidiary of Emera an amount of $1,368 (2009 - $nil) which was included as an operating expense on the consolidated statement of operations.

In 2010, APUC entered into a one year contract with a subsidiary of Emera to provide lead market participant services for fuel capacity and forward reserve markets in ISO NE for the Windsor Locks facility. During 2010 APUC paid U.S. $196 (2009 - $nil) in relation to this contract. In the same period, APUC issued a letter of credit to a subsidiary of Emera in an amount of U.S. $500 in conjunction with this contract. Subsequent to December 31, 2010, this letter of credit was replaced with a corporate guarantee.

On December 21, 2010, a subsidiary of Emera acquired Maine & Maritimes Corporation), the parent company of Maine Public Service Company (“MPS”). Subsequent to the date of this acquisition, the Energy Services Business sold electricity of U.S. $144 (2009 – nil) to MPS.

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

43

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2010 and 2009

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

15. Commitments and Contingencies

(a) Land and Water Leases

Certain of the Company’s operating entities have entered into agreements to lease either land, water rights or both that are used in the generation of electricity or to pay, in lieu of property tax, an amount based on electricity production. The terms of these leases have varying maturity dates that continue up to 2048. These payments typically have a fixed and variable component. The variable fee is generally linked to actual power production or gross revenue. APUC incurred costs of $2,231 during 2010 (2009 - $2,823) in respect of these agreements for all of its operating entities.

(b) 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. 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.

(c) Commitments

Legislation in the Province of Quebec requires technical assessments be made of all dams within the province and remediation of any technical deficiencies identified in accordance with the assessment. APUC is in the process of conducting the assessments as required. Based on assessments to date, some of which are preliminary, APUC has estimated potential remedial measures involving capital expenditures of approximately $17,129 which may be required to comply with the legislation and which would be invested over a five year period or longer. APUC continues to explore alternatives to reduce or mitigate these potential capital expenditures, including technical alternatives and cost sharing with other stakeholders.

An AirSource affiliate, St. Leon Wind Energy LP (“St. Leon LP”) has entered into right-of-way agreements (collectively, the “Land Rights”), with approximately 50 local landowners, providing for a minimum term of 40 years. The Land Rights agreements provide for an annual rent payable per MW-hr generated from turbines installed on the land rented, subject to a minimum payment per wind turbine. Land without wind turbines is leased at a cost on a per acre basis. The total commitment over the term of the St. Leon power purchase agreement is estimated at $3,605.

16. Cash dividends

All cash dividends of the Company are made on a discretionary basis as determined by the Board of Directors of the Company. In 2010, the Company paid quarterly dividends of $0.06 per share. For the year ended December 31, 2010, the Company paid cash dividends to shareholders totaling $22,765 (2009 - $18,999) or $0.24 per unit / per share (2009 - $0.24).

Total distributions to the unitholders of the AirSource exchangeable units for 2010 were $nil (2009 - $323) which was recorded as a reduction in non controlling interest on the consolidated balance sheet.

44

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2010 and 2009

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

17. Non cash working capital and Supplemental cashflow Information

The change in non cash working capital is comprised of the following:

	2010			2009
Accounts receivable	$	(6,813	)	$	6,720
Income tax receivable		1,143			395
Prepaid expenses		1,153			(1,842	)
Accounts payable and accrued liabilities		5,050			(6,042	)
Current income tax liability		195			(536	)
	$	728		$	(1,305	)

The following table sets forth non-cash investing and financing activities and other cash flow information:

	2010			2009
Taxes & Interest paid:
Income taxes paid / (received)	$	(285	)	$	873
Interest paid	$	21,562		$	19,956
Non-cash transactions:
Property installed by developers and conveyed	$	2,541		$	223

18. Basic and diluted net earnings per share

Basic and diluted earnings per share have been calculated on the basis of the weighted average number of shares outstanding during the year. The weighted average number of shares outstanding during the year are as follows:

	2010		2009
Weighted average shares – basic		94,338,193		79,830,906
Shares issuable on conversion of AirSource exchangeable units		—		1,499,222
Weighted average shares – diluted		94,338,193		81,330,128

Shares or Trust units issuable on conversion of exchangeable units are calculated at the year end based on the weighted average exchangeable units outstanding during the year and applying the rate of exchange. The shares potentially issuable as a result of the convertible debentures and under stock option plans are excluded from this calculation as they are anti-dilutive.

45

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2010 and 2009

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

19. Interest, dividend and other income

Interest, dividend and other income includes the following items:

	2010		2009
Interest income	$	1,138	$	710
Dividend income		2,928		2,928
Equity income		431		361
Gain on sale of land and land rights		—		1,451
Other		465		951
	$	4,962	$	6,401

20. Other revenue

Other revenue consists of the following:

	2010			2009
Natural gas sales	$	(109	)	$	588
Hydro mulch sales		1,318			3,260
Red Lily development fees		209			—
Red Lily construction services		1,913			—
	$	3,331		$	3,848

46

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2010 and 2009

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

21. Segmented Information

APUC has two broad operating segments: APCo which owns or has interests in 48 renewable energy facilities and 14 thermal energy facilities representing more than 490 MW of installed electrical generation capacity; and Liberty Utilities which owns and operates 19 utilities in the United States of America providing water or wastewater services in the states of Arizona, Texas, Missouri and Illinois.

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. 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.

Within Liberty Utilities, Liberty Water provides transportation and delivery of water and wastewater in its service areas.

The operations and assets for these segments are as follows:

Operational segments

APUC’s reportable segments are APCo - Renewable Energy, APCo - Thermal Energy and Liberty Water. The development activities are reported under Renewable Energy or Thermal Energy as appropriate. For purposes of evaluating divisional performance, the Company allocates the realized portion of the gain 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. Dividend income was previously allocated to the Thermal division based on the operations of the underlying investment. In 2010, Management reviewed the performance of these investments separately from the facilities that the Company manages directly. Interest expense is allocated to the divisions based on the project level debt related to the facilities in each division. Interest expense on the revolving credit facility and other administrative costs were previously allocated to the corporate segment. In 2010, Management’s evaluation of divisional performance considered an allocation between the reporting segments based on a percentage of the reporting segments share of the total property, plant and equipment and intangible assets. 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 comparative figures have been reclassified to conform to the allocation adopted this year.

The operations and assets for these segments are as follows:

47

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2010 and 2009

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

21. Segmented Information (continued)

Operational Segments (continued)

Year ended December 31, 2010
	Algonquin Power									Liberty Utilities			Corporate			Total
	Renewable Energy			Thermal Energy			Total
Revenue
Energy sales	$	80,117		$	52,609		$	132,726		$	—		$	—		$	132,726
Waste disposal fees		—			9,039			9,039			—			—			9,039
Water reclamation and distribution		—			—			—			37,786			—			37,786
Other revenue		2,122			1,209			3,331			—			—			3,331
Total revenue		82,239			62,857			145,096			37,786			—			182,882
Operating expenses		29,481			46,296			75,777			22,074			—			97,851
		52,758			16,561			69,319			15,712			—			85,031
Other administration costs		(4,674	)		(1,825	)		(6,499	)		(1,890	)		(6,497	)		(14,886	)
Foreign exchange loss		—			—			—			—			528			528
Interest expense		(7,742	)		(782	)		(8,524	)		(1,908	)		(15,180	)		(25,612	)
Interest, dividend and other income		783			495			1,278			85			3,599			4,962
Gain / (loss) on derivative financial instruments		(5,486	)		—			(5,486	)		—			4,383			(1,103	)
Write down of property plant and equipment		(1,836	)		(656	)		(2,492	)		—			—			(2,492	)
Amortization of property, plant and equipment		(17,233	)		(11,362	)		(28,595	)		(7,659	)		(175	)		(36,429	)
Amortization of intangible assets		(6,670	)		(2,774	)		(9,444	)		(700	)		—			(10,144	)
Net earnings / (loss) before income taxes, and non-controlling interest		9,900			(343	)		9,557			3,640			(13,342	)		(145	)
Property, plant and equipment	$	412,549		$	151,260		$	563,809		$	164,775		$	492		$	729,076
Intangible assets		28,287			23,104			51,391			22,495			—			73,886
Total assets		467,979			195,181			663,160			205,770			111,987			980,917
Capital expenditures		2,331			11,596			13,927			6,644			260			20,831
Acquisition of operating entities		40,281			—			40,281			5,243			—			45,524

48

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2010 and 2009

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

21. Segmented Information (continued)

Operational Segments (continued)

Year ended December 31, 2009
	Algonquin Power									Liberty Utilities			Corporate			Total
	Renewable Energy			Thermal Energy			Total
Revenue
Energy sales	$	68,227		$	62,209		$	130,436		$	—		$	—		$	130,436
Waste disposal fees		—			14,468			14,468			—			—			14,468
Water reclamation and distribution		—			—			—			38,513			—			38,513
Other revenue		—			3,848			3,848			—			—			3,848
Total revenue		68,227			80,525			148,752			38,513			—			187,265
Operating expenses		22,279			57,299			79,578			23,158			—			102,736
		45,948			23,226			69,174			15,355			—			84,529
Other administration costs		(5,791	)		(2,812	)		(8,603	)		(226	)		(2,733	)		(11,562	)
Foreign exchange loss		—			—			—			—			1,261			1,261
Interest expense		(7,345	)		(1,098	)		(8,443	)		(2,049	)		(10,895	)		(21,387	)
Interest, dividend and other income		1,226			821			2,047			1,368			2,986			6,401
Gain / (loss) on derivative financial instruments		2,682			(829	)		1,853			343			15,122			17,318
Write down of property plant and equipment		—			(5,354	)		(5,354	)		—			—			(5,354	)
Write down of note receivable		—			(1,103	)		(1,103	)		—			—			(1,103	)
Amortization of property, plant and equipment		(16,934	)		(13,087	)		(30,021	)		(8,557	)		—			(38,578	)
Amortization of intangible assets		(2,654	)		(3,916	)		(6,570	)		(735	)		—			(7,305	)
Earnings / (loss) from operations before income taxes, non-controlling interest, and corporatization costs		17,132			(4,152	)		12,980			5,499			5,741			24,220
Management internalization costs		—			—			—			—			(4,693	)		(4,693	)
Other corporatization costs		—			—			—			—			(3,460	)		(3,460	)
Net earnings / (loss) before income taxes, and non-controlling interest		17,132			(4,152	)		12,980			5,499			(2,412	)		16,067
Property, plant and equipment	$	403,192		$	176,171		$	579,363		$	169,987		$	—		$	749,350
Intangible assets		30,602			30,436			61,038			24,891			—			85,929
Total assets		451,936			245,582			697,518			203,444			112,451			1,013,413
Capital expenditures		1,114			3,521			4,635			6,174			107			10,916
Acquisition of operating entities		—			—			—			(1,177	)		—			(1,177	)

49

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2010 and 2009

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

21. Segmented Information (continued)

Operational Segments (continued)

All energy sales are earned from contracts with large public utilities. The following utilities contributed more than 10% of these total revenues in either 2010 or 2009: Hydro Québec 14% (2009 - 17%), Pacific Gas and Electric 10% (2009 - 12%), Manitoba Hydro 15% (2009 – 15%), and Connecticut Light and Power 4% (2009 - 18%). The Company has mitigated its credit risk to the extent possible by selling energy to these large utilities in various North American locations.

Geographic Segments

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:

	2010		2009
Revenue
Canada	$	75,108	$	82,364
United States		107,774		104,901
	$	182,882	$	187,265
Property, plant and equipment
Canada	$	466,205	$	440,490
United States		262,871		308,860
	$	729,076	$	749,350
Intangible assets
Canada	$	43,305	$	47,916
United States		30,581		38,013
	$	73,886	$	85,929
Other assets
Canada	$	1,414	$	1,916
United States		8,203		2,926
	$	9,617	$	4,842

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

50

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2010 and 2009

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

22. Financial instruments

a) Fair Value of financial instruments

	Carrying amount		2010 Fair value		Carrying amount		2009 Fair value
Cash		5,146		5,146		2,796		2,796
Short-term investments		3,674		3,674		40,010		40,010
Accounts receivable		27,082		27,082		20,484		20,484
Restricted cash		3,563		3,563		4,316		4,316
Notes receivables		18,744		18,744		4,460		4,460
Total financial assets		58,209		58,209		72,066		72,066
Accounts payable and accrued liabilities		33,506		33,506		33,219		33,219
Dividends payable		5,721		5,721		1,857		1,857
Long-term liabilities		259,131		261,321		244,772		247,119
Other long-term liabilities		31,883		31,883		26,253		26,253
Convertible debentures		170,975		216,769		173,257		198,892
Interest swaps		5,440		5,440		8,226		8,226
Energy forward purchase		378		378		—		—
Foreign exchange contracts		45		45		1,469		1,469
Total financial liabilities		507,079		555,063		489,053		517,035

The Company has determined that the carrying value of its short-term financial assets and liabilities approximates fair value at December 31, 2010 and 2009 due to the short-term maturity of these instruments.

Long term investments and notes receivable include equity instruments and notes receivable. The equity instruments do not have a quoted market price in an active market, and fair value cannot be reliably measured. 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 and convertible debentures at fixed interest rates and variable rates. The estimated fair value is calculated using the current interest rates.

Advances in aid of construction included in other long-term liabilities (note – 1 (l)) do not bear interest and the amount to be repaid is subject to uncertainty and estimation. The carrying value is estimated based on historical payment patterns with the amount estimated to not be paid being recorded as a contribution in aid of construction which reduces the carrying amount of the related assets. The fair value is considered to approximate the book value.

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.

51

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2010 and 2009

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

22. Financial instruments (continued)

b) Fair Value Hierarchy

The fair value hierarchy of financial assets and liabilities accounted for at fair value at December 31, 2010 are as follows:

	Level 1		Level 2		Level 3		Total
Interest swap –St Leon		—		5,440		—		5,440
Energy forward purchase		—		378		—		378
Foreign exchange contracts		—		45		—		45
Total financial liabilities at fair value		—		5,863		—		5,863

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 lever 3 during the year ended December, 31, 2010. No assets or liabilities are measured at fair value on a recurring basis using unobservable inputs (Level 3).

c) Effect of derivative instruments on the Consolidated Statement of Operations

Loss/(gain) on derivative financial instruments consist of the following:

	2010			2009
Change in unrealized loss/(gain) on derivative financial instruments:
Foreign exchange contracts	$	(1,424	)	$	(15,682	)
Interest rate swaps		(2,787	)		(7,424	)
Energy forward purchase contracts		(2,931	)		—
Total change in unrealized loss/(gain) on derivative financial instruments	$	(7,142	)	$	(23,106	)
Realized loss/(gain) on derivative financial instruments:
Foreign exchange contracts	$	(620	)	$	284
Interest rate swaps		5,929			5,504
Energy forward purchase contracts		2,936			—
Total realized loss/(gain) on derivative financial instruments	$	8,245		$	5,788
Loss/(gain) on derivative financial instruments	$	1,103		$	(17,318	)

52

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2010 and 2009

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

22. Financial instruments (continued)

(d) 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.

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 and accounts receivable. The Company limits its exposure to credit risk with respect to cash equivalents by maintaining minimal cash balances and 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 in the United States. In this regard, the credit risk related to Utility Services accounts receivable balances of US$4,996 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.

53

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2010 and 2009

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

22. Financial instruments (continued)

Credit Risk (continued)

As at December 31, 2010 the Company’s exposure to credit risk for these financial instruments was as follows:

	December 31, 2010
	Canadian $		US $
Cash and cash equivalents	$	1,878	$	3,285
Short term investments		—		3,694
Accounts receivable		11,877		15,328
Allowance for Doubtful Accounts		—		(40	)
Note Receivable		16,733		2,021
	$	30,488	$	24,288

There are no material past due amounts in accounts receivable.

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, 2010, in addition to cash on hand of $5,146 the Company had $44,400 available to be drawn on its senior debt facility. The senior credit facility contains covenants which may limit amounts available to be drawn.

	Total		Due less than 1 year		Due 2 to 3 years		Due 4 to 5 years		Due after 5 years
Long term debt obligations	$	259,131	$	70,490	$	3,238	$	68,395	$	117,008
Convertible Debentures		185,342		—		—		62,469		122,873
Interest on long term debt obligations		164,830		25,670		48,198		35,889		55,073
Accounts Payable		33,506		33,506		—		—		—
Derivative financial instruments:
Currency Forwards		45		45		—		—		—
Interest Rate Swaps		5,439		1,959		2,504		976		—
Commodity Swap		378		378		—		—		—
Lease Payments		523		212		243		68		—
Other obligations		9,255		466		931		931		6,927
Total obligations	$	658,449	$	132,726	$	55,114	$	168,728	$	301,881

54

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2010 and 2009

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

22. Financial instruments (continued)

Foreign Currency Risk

The Company 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. Based on the fair value of the forward contracts using the exchange rates as at December 31, 2010, the exercise of these forward contracts will result in the use of $45 in fiscal 2012. Assuming a decrease in the strength of the US dollar relative to the Canadian dollar of $0.10 at December 31, 2010 with a corresponding change in the forward yield curve, the fair value of the outstanding forward exchange contracts would increase by $300, increasing the expected cash generated during fiscal 2012 by $300.

As at December 31, 2010, APUC had outstanding foreign exchange forward contracts to sell US$3,000 (2009 - $39,760) at an average rate of $1.00 (2009- $1.02) and having a fair value liability of $45 (2009 - $1,469).

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 as well as interest earned on its cash on hand. The Company has performed sensitivity analysis on interest rate risk at December 31, 2010 to determine how a change in interest rates would impact equity and net earnings:

Senior credit facility

The Company’s senior debt facility has a balance of $64,500 as at December 31, 2010. Assuming the current level of borrowings, a 1% change in the variable rate charged would impact interest expense by $645 during the twelve months ended December 31, 2010. Although this underlying debt with the project lenders carries a variable rate of interest tied to Canadian Bank’s prime rate, the Company had previously entered into a fixed for floating interest rate swap related to $100,000 of this debt covering the period between June 30, 2008 and December 2010. APUC effectively fixed its interest expense on this portion of the facility at a rate of 3.24% in 2009 and 4.18% in 2010. At December 31, 2010, the fair value of the interest rate swap was $nil as it had expired (2009 - $3,260 liability). This swap arrangement requires the payment of a fixed rate of interest by the Company in exchange for receipt of a variable rate of interest. The Company has not used hedge accounting for this instrument and therefore changes in fair value are recorded in earnings as they occur and form part of the gain or loss on financial instruments on the consolidated statements of operations.

55

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2010 and 2009

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

22. Financial instruments (continued)

Airsource –St Leon

The Algonquin (AirSource) Power LP (“Airsource”) project debt at the St. Leon facility has a balance of $68,789 as at December 31, 2010. Assuming the current level of borrowings, a 1% change in the variable rate charged would have impacted interest expense by $687 during the twelve months ended December 31, 2010. Although this underlying debt with the project lenders carries a variable rate of interest tied to Canadian Bank’s prime rate, in 2006 the Company entered into a fixed for floating interest rate swap related to this debt until September 2015. This swap arrangement requires the payment of a fixed rate of interest by the Company in exchange for receipt of a variable rate of interest that mirrors the underlying debt’s interest payment schedule. These payments effectively minimize volatility in the cash interest on this debt facility through an offset for any change to interest payments as a result of market rate fluctuations. At December 31, 2010, the fair value of the interest rate swap was a net $5,440 liability (2009 - $4,966). APUC has elected not to use hedge accounting for the swap transaction and records the fair value of the swap on the consolidated balance sheets. Any gain or loss in fair value is recognized in the consolidated statements of operations.

Sanger

The Company’s project debt at the Sanger facility has a balance of U.S. $19,200 as at December 31, 2010. Assuming the current level of borrowings, a 1% change in the variable interest rate charged would impact interest expense by $192 during the twelve months ended December 31, 2010. This analysis assumes that all other variables, in particular foreign currency rates, remain constant.

Market Risk

APUC provides energy requirements to various customers under contract at fixed rates. While 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.

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 2010, APUC acquired short term forward energy purchase contracts from the Tinker Acquisition related to the energy services business. APUC has committed to acquire approximately 12,000 MW-hrs of energy over the next 2 months at an average rate of approximately $70.00 per MW-hr. The fair value of these forward energy hedge contracts at December 31, 2010 was a net liability of $378 (2009 - $nil).

56

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2010 and 2009

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

23. Capital disclosures

The Company views its capital structure in terms of its debt levels, both at a project and an overall company level, in conjunction with its equity balances.

The Company’s objectives when managing capital are:

• To maintain appropriate debt and equity levels in conjunction with standard industry practices and to limit financial constraints on the use of capital.

• To ensure capital is available to finance capital expenditures sufficient to maintain existing assets.

• To ensure generation of cash is sufficient to fund sustainable distributions to Unitholders as well as meet current tax and internal capital requirements.

• To maintain sufficient cash reserves on hand to ensure sustainable dividends made to shareholders.

• To have proper credit facilities available for ongoing investment in growth and investment in development opportunities.

The Company monitors its cash position on a regular basis to ensure funds are available to meet current operating as well as capital expenditures. In addition, the Company regularly reviews its capital structure to ensure its individual business units are using a capital structure which is appropriate for their respective industries.

57

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2010 and 2009

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

24. U.S. GAAP Reconciliation

The Company follows generally accepted accounting principles in Canada (GAAP), which differs in certain material respects from generally accepted accounting principles in the United States and from practices prescribed by the United States Securities and Exchange Commission (U.S. GAAP). The following information reconciles these consolidated financial statements to U.S. GAAP.

Reconciliation of net earnings under Canadian GAAP to U.S. GAAP

	Year ended December 31
	2010			2009
Net earnings, Canadian GAAP	$	19,639		$	31,257
Adjustments, net of tax of $563 (2009- $991)
Convertible debentures (b),(d)		572			(1,850	)
Deferred transaction costs (f)		(2,261	)		(1,106	)
Non controlling interest (c)		—			2,251
Total adjustments		(1,689	)		(705	)
Net earnings, U.S. GAAP		17,950			30,552
Other comprehensive income/(loss), Canadian and U.S. GAAP		(51,133	)		(27,270	)
Total comprehensive income/(loss), U.S. GAAP		(33,182	)		3,282
Basic net earnings per share	$	0.19		$	0.38
Diluted net earnings per share	$	0.19		$	0.38

The Application of U.S. GAAP results in difference to the following balance sheet items:

	December 31, 2010						December 31, 2009
	Canadian GAAP			U.S. GAAP			Canadian GAAP			U.S. GAAP
Property, plant and equipment		729,076			728,686			749,350			749,350
Other assets – deferred transaction costs (f)		4,098			—			1,474			—
Deferred financing costs (b(iii),(e))		258			5,991			200			6,001
Long-term liabilities (e)		259,131			259,973			244,772			244,970
Convertible debentures (b(iii),(e)(d)		170,975			181,758			173,257			185,600
Future income tax liability (h)		81,467			79,956			80,827			79,879
Non-controlling interest (c)		—			—			—			—
Temporary equity (a), (c)		—			—			—			—
Additional paid-in-capital (b(ii)),(g)		—			1,496			—			1,487
Shareholders’ capital (a),(b),(c),(d),(g)		796,576			795,443			787,037			785,827
Deficit		(347,802	)		(357,034	)		(344,676	)		(352,219	)

58

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2010 and 2009

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

24. US GAAP Reconciliation (continued)

Reconciliation of deficit under Canadian GAAP to U.S. GAAP

	As at December 31
	2010			2009
Deficit, Canadian GAAP	$	(347,802	)	$	(344,676	)
Adjustments, net of tax
Convertible debentures (b), (d)		(1,311	)		(1,883	)
Non controlling interest (c)		(4,554	)		(4,554	)
Deferred transaction costs (f)		(3,367	)		(1,106	)
Total adjustments		(9,232	)		(7,543	)
Deficit, U.S. GAAP	$	(357,034	)	$	(352,219	)

Description of significant differences

a) Unit Exchange Offer

On October 27, 2009, Algonquin Power Income Fund (the “Fund”) completed a reverse take-over transaction (the “Transaction”) of Hydrogenics Corporation (“Hydrogenics”) which resulted in the Fund’s Unitholders becoming shareholders in Hydrogenics which was immediately renamed Algonquin Power & Utilities Corp. As a result, the Fund itself became a wholly owned subsidiary of APUC. For Canadian and U.S. GAAP purposes, APUC is considered a continuation of the Fund except for the legal capital of the Fund which is adjusted to reflect the legal capital of APUC.

Prior to the Transaction, the Fund’s trust units contained a redemption feature which was required for the Fund to retain its Canadian mutual fund trust status. For Canadian GAAP purposes, the Trust units were considered permanent equity and were presented as a component of Unitholders’ equity. Under U.S. GAAP, equity with a redemption feature is presented outside of permanent equity, as temporary equity between the liability and equity sections of the balance sheet. As such, the trust units of $721,736 were reclassed from permanent equity to temporary equity for U.S. GAAP purposes up to October 27, 2009.

59

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2010 and 2009

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

24. US GAAP Reconciliation (continued)

b) CD Exchange Offer

Contemporaneously with the Unit Exchange Offer, on October 27, 2009 a convertible debenture exchange offer (the “CD Exchange Offer”) was made by APUC to debentureholders of the Fund to allow them to receive debentures issued by APUC.

(i) Similar to Canadian GAAP, under U.S. GAAP the change in coupon rates and maturity terms of the convertible debentures under the CD Exchange Offer is considered to be a debt modification and not an extinguishment based on the Company’s evaluation of the changes in cash flows and fair value of the conversion options under the terms of the revised debt agreements. The consolidated balance sheet of APUC under Canadian GAAP reflects the convertible debentures at their original carrying values, net of an allocation of transaction costs of approximately $2,544 associated with the CD Exchange Offers. Under U.S. GAAP these transaction costs of $2,544 were expensed when incurred in 2009 since the costs were paid to third parties and not the debtor. This results in a reduction of $337 (2009 - $53) in the amount of effective interest on convertible debentures under U.S. GAAP in comparison to Canadian GAAP.

(ii) The change in conversion price of the Series 1 and Series 2 convertible debentures under the CD Exchange Offer results in a change in the fair value of the conversion feature of $1,179 and $308, respectively. Under U.S. GAAP, the combined fair value of the conversion feature of $1,487 is recorded as a discount on debt, with an offsetting entry to additional paid-in-capital. Under Canadian GAAP, the offsetting entry is recorded in equity. An adjustment of $1,388 (2009 – 1,487), net of a converted portion of $99 (2009 - $nil) reflects the reclassification of conversion feature recorded as equity under Canadian GAAP, to additional paid-in capital under U.S. GAAP.

(iii) Under U.S. GAAP the adjustment for the conversion of $21,209 of the Series 1 convertible debentures into common shares does not result in any Canadian GAAP difference in earnings.

However, under Canadian GAAP the pro rata share of existing deferred financing charges associated with the Series I debentures of $306 is recorded as a charge against equity upon conversion of $21,209 of debentures into common shares, with a corresponding adjustment to convertible debentures. Under U.S. GAAP, the same net amount is charged against equity however, the corresponding adjustment of $306 is made to deferred financing costs to reflect the different classification of deferred charges for Canadian and U.S. GAAP purposes.

60

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2010 and 2009

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

24. US GAAP Reconciliation (continued)

c) Non controlling interest

Exchangeable units (“AirSource Exchangeable Units”) were issued by Algonquin (AirSource) Power LP (“Algonquin AirSource”), a subsidiary of the Fund, when Algonquin AirSource acquired AirSource Power Fund I LP on June 29, 2006. The AirSource Exchangeable Units entitled the holders to receive distributions which are equivalent to the Fund’s distributions, as long as the facility which was acquired upon acquisition of AirSource generated adequate cash flows.

Under Canadian GAAP the AirSource Exchangeable Units were recorded in the Company’s consolidated financial statements as “Non controlling interest”. The portion of income or loss attributable to this non controlling interest and distributions to holders of the exchangeable units are recorded as a reduction to the carrying amount of the non controlling interest. Under U.S. GAAP the AirSource Exchangeable Units are classified along with the Trust Units outside of permanent equity as temporary equity since they are able to be converted at the holder’s option to the Fund’s Trust Units. The temporary equity was initially recorded at an amount equal to the redemption value based on the terms of the AirSource Exchangeable Units. Any increase in the redemption value of the AirSource Exchangeable Units is recorded as an adjustment through deficit and any downward adjustment is restricted only to the extent of previously recorded increases in the carrying amount arising from such adjustments. No adjustment was required to the carrying amount of the AirSource Exchangeable Units in temporary equity. Under U.S. GAAP the proportion of income attributable to the AirSource Exchangeable Units non controlling interest of $nil (2009 - $2,251) is recorded to deficit rather than through earnings and distributions to the AirSource Exchangeable Unit holders of $nil (2009 - $323) are recorded as a charge to deficit.

On December 31, 2009, all remaining Air Source units were converted to APUC shares. Under both Canadian and U.S. GAAP, when the AirSource Exchangeable Units are converted to shares, the non controlling interest (temporary equity under U.S. GAAP) on the consolidated balance sheet is reduced on a pro-rata basis together with a corresponding increase in shares. However, since the carrying amount of the non-controlling interest per Canadian GAAP differs from the carrying amount in temporary equity per U.S. GAAP, the amount transferred to shareholders’ capital differs by $4,554.

d) Convertible debentures

Under Canadian GAAP, the carrying amount of the convertible debentures was bifurcated into equity (the conversion option) and debt whereas under U.S. GAAP, the convertible debentures do not have the features that would require bifurcation. Accordingly, an adjustment to the balance sheets of $4,252 (2009- $4,275) in relation to the Series 3 Convertible Debentures reflects the reclassification of the value attributed to the equity components recorded under Canadian GAAP, to convertible debentures.

Under Canadian GAAP, the accretion of the residual carrying value of the convertible debentures to the face value of the convertible debentures over the life of the instrument is charged to interest expense. Under U.S. GAAP, no such accretion is required if the conversion feature is not required to be bifurcated. This GAAP difference resulted in a reversal of accretion of $426 (2009 - $27) recorded under Canadian GAAP.

61

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2010 and 2009

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

24. US GAAP Reconciliation (continued)

e) Financing costs

The Company records financing costs associated with issuance of debt instruments as a reduction to long-term liabilities and convertible debentures under Canadian GAAP. Under U.S. GAAP, such costs are presented in assets as deferred financing costs. Accordingly, the reclassification adjustment reflects a cumulative increase of $840 (2009 - $197) in long-term liabilities and $4,893 (2009 - $5,604) in convertible debentures with a corresponding increase in deferred financing costs of $5,733 (2009 - $5,801).

f) Business combinations and transaction costs

Under Canadian GAAP, the Company recorded $3,014 (2009 - $1,474) of deferred transaction costs in connection with future business acquisitions. Under U.S. GAAP, acquisition-related costs are expensed as incurred.

g) Stock-based compensation

Under U.S. GAAP, the stock-based compensation of $108 (2009 - $nil) is recorded as compensation expense with a balancing entry to additional paid-in-capital. Under Canadian GAAP, the balancing entry is recorded in contributed surplus. An adjustment of $108 (2009 - $nil) reflects the reclassification of stock-based compensation recorded as contributed surplus under Canadian GAAP to additional paid-in capital under U.S. GAAP.

h) Income taxes

The adjustments reflect the future tax impact of the above U.S. GAAP adjustments.

i) Cash flow statement

The consolidated cash flow statement prepared in accordance with Canadian GAAP presents substantially the same information that is required under U.S. GAAP with the exception of deferred transaction costs in connection with future acquisitions of $3,014 (2009 - $1,474) as described in note g) which under U.S. GAAP would be reflected in as cash used in operating activities unlike in Canadian GAAP where it is classified as investing activity. Additionally the Company presents a subtotal in its Canadian GAAP statement of cash from operating activities before change in non-cash operating working capital. This subtotal is not permitted under U.S. GAPP.

j) Adoption of new accounting pronouncements

i) Credit quality:

Effective December 31, 2010, APUC adopted ASU 2010-20, Receivables (Topic 310): Disclosures about the Credit Quality of Financing Receivables and the Allowance for Credit Losses, which increases disclosures about credit quality of financing receivables and the allowance for credit losses, and requires disclosures to be made at a greater level of disaggregation. The adoption of this guidance in 2010 has been reflected in the Company’s disclosures relating to notes receivable.

ii) Fair value disclosure:

Effective January 1, 2010, APUC adopted ASU 2010-06, Improving Disclosures about Fair Value Measurements which requires more detailed information on fair-value disclosures. The adoption of this guidance in 2010 is reflected in note 22 of the consolidated financial statements.

62

ALGONQUIN POWER & UTILITIES CORP.

Notes to the Consolidated Financial Statements

December 31, 2010 and 2009

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

24. US GAAP Reconciliation (continued)

iii) Variable interest entities:

Effective January 1, 2010, APUC adopted FAS 167: Amendments to FASB Interpretation No. 46(R) which addresses (1) the effects on certain provisions of FASB Interpretation No. 46 (revised December 2003), Consolidation of Variable Interest Entities, as a result of the elimination of the qualifying special-purpose entity concept in FASB Statement No. 166, Accounting for Transfers of Financial Assets, and (2) the application of certain key provisions of Interpretation 46(R), including those in which the accounting and disclosures under the Interpretation do not always provide timely and useful information about an enterprise’s involvement in a variable interest entity. The adoption of this standard did not have an impact on the Company’s financial statements.

iv) Subsequent events:

In February 2010, the FASB issued ASU No. 2010-09 “Subsequent Events (ASC Topic 855) “Amendments to Certain Recognition and Disclosure Requirements” (“ASU No. 2010-09”). ASU No. 2010-09 requires an entity that is an SEC filer to evaluate subsequent events through the date that the financial statements are issued and removes the requirement for an SEC filer to disclose a date, in both issued and revised financial statements, through which the filer had evaluated subsequent events.

k) Recently issued accounting pronouncements not yet adopted

i) Revenue recognition:

In October 2009, the FASB issued ASU 2009-13, Revenue Recognition (Topic 605): Multiple-Deliverable Revenue Arrangements—a consensus of the FASB Emerging Issues Task Force (“ASU 2009-13”). ASU 2009-13 requires entities to allocate revenue in an arrangement using estimated selling prices of the delivered goods and services based on a selling price hierarchy. The ASU eliminates the residual method of revenue allocation and requires revenue to be allocated using the relative selling price method. ASU 2009-13 should be applied on a prospective basis for revenue arrangements entered into or materially modified in fiscal years beginning on or after June 15, 2010, with early adoption permitted. The Company does not expect adoption of ASU 2009-13 to have a material impact on the Company’s consolidated financial statements.

ii) Goodwill:

In December 2010, the FASB issued ASU 2010-28, Intangibles—Goodwill and Other (Topic 350):When to Perform Step 2 of the Goodwill Impairment Test for Reporting Units with Zero or Negative Carrying Amounts, a consensus of the FASB Emerging Issues Task Force (Issue No. 10-A). ASU 2010-28 modifies Step 1 of the goodwill impairment test under ASC Topic 350 for reporting units with zero or negative carrying amounts to require an entity to perform Step 2 of the goodwill impairment test if it is more likely than not that a goodwill impairment exists. ASU 2010-28 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2010. The Company expects that the adoption of ASU 2010-28 in 2012 will not have a material impact on its consolidated financial statements.

25. Comparative figures

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

63